Vector Surge

Electric Power Systems Research 77 (2007) 170–180

Characteristics of vector surge relays for distributed synchronous generator protection Walmir Freitas a,∗ , Wilsun Xu b , Zhenyu Huang c , Jose C.M. Vieira a a

Department of Electrical Energy Systems, State University of Campinas, 13083-852 Campinas, Sao Paulo, Brazil Department of Electrical and Computer Engineering, University of Alberta, Edmonton, Alta., Canada T6G 2V4 c Energy Science and Technology Division, Pacific Northwest National Laboratory, 99352 Richland, WA, USA

b

Received 12 September 2005; received in revised form 17 February 2006; accepted 17 February 2006 Available online 17 April 2006

Abstract This work presents a detailed investigation on the performance characteristics of vector surge relays used to detect islanding of distributed synchronous generators. A detection time versus active power imbalance curve is proposed to evaluate the relay performance. Computer simulations are used to obtain the performance curves. The concept of critical active power imbalance is introduced based on these curves. Main factors affecting the performance of the relays are analyzed. The factors investigated are voltage-dependent loads, load power factor, inertia constant of the generator, generator excitation system control mode, feeder length and R/X ratio as well as multi-distributed generators. The results are a useful guideline to evaluate the effectiveness of anti-island schemes based on vector surge relays for distributed generation applications. © 2006 Elsevier B.V. All rights reserved. Keywords: Distributed generation; Islanding detection; Synchronous generators; Vector surge relays; Vector shift relays

1. Introduction Distributed generation has recently gained a lot of momentum in the power industry due to market deregulation, technological advances, governmental incentives and environment impact concerns [1–3]. An important requirement for the connection of synchronous generators to distribution networks is the protection system capability of islanding detection. Islanding occurs when a portion of the distribution system becomes electrically isolated from the remainder of the power system, yet continues to be energized by distributed generators. This is also known as loss of mains or loss of grid [3]. Failure to trip islanded generators can lead to a number of problems to the generator and the connected loads. The current industry practice is to disconnect all distributed generators immediately after the occurrence of islands [4,5]. Typically, a distributed generator should be disconnected within 200–400 ms after loss of main supply. In order to achieve such a goal, each distributed synchronous generator must be equipped with an islanding detection device. The

∗

Corresponding author. Tel.: +55 19 37883740; fax: +55 19 32891395. E-mail address: [email protected] (W. Freitas).

0378-7796/$ – see front matter © 2006 Elsevier B.V. All rights reserved. doi:10.1016/j.epsr.2006.02.011

common devices used for this purpose are the modified versions of the under/over voltage and under/over frequency relays. Among them, devices based on variations of frequency have been recognized as the most reliable option by the industry so far. Representative examples of such relays are the rate of change of frequency relay (ROCOF) and the vector surge relay (VSR), which is also known as vector shift or voltage jump relay [1–3]. However, it has been well recognized that such relays tend to fail when the mismatch or imbalance between the generation and the load in the islanded system is small. As more and more distributed generators are added to utility systems, it has become clear that a good understanding on the operating characteristics of these relays is important. The results can be very useful for utility engineers to evaluate the reliability and robustness of a given distributed generation anti-islanding scheme. The objective of this paper is to present our investigation results on this subject. The concepts of detection time versus active power imbalance curve and critical active power imbalance are proposed to characterize the relay performance. Since vector surge relays have been widely used by the industry, it is selected as the study subject in this paper. However, the proposed method can be applied to other types of anti-islanding relays as well.

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Fig. 1. Equivalent circuit of a synchronous generator in parallel with utility.

This paper is organized as follows. The principle of vector surges relays is explained in Section 2. The detection time versus active power imbalance curves and the concept of critical active power imbalance are discussed in Section 3. The main factors affecting the performance of vector surge relays are investigated in Section 4. The factors investigated are voltage-dependent loads, load power factor, inertia constant of the generator, generator excitation system control mode, feeder length and R/X ratio as well as multi-distributed generators. Finally, in Section 5, the main conclusions are analyzed. 2. Principle of vector surge relays When a synchronous generator is operating in parallel with a distribution network, as depicted in Fig. 1, there is a voltage drop
V between the terminal voltage VT and the generator internal voltage EI due to the generator current ISG passing through the generator reactance Xd . Consequently, there is a displacement angle between the terminal voltage and the generator internal voltage, whose phasor diagram is presented in Fig. 2(a). In Fig. 1, if the circuit breaker CB opens, due to a fault for example, the system composed by the generator and the load L becomes islanded. At this instant, the synchronous machine begins to feed a larger load (or smaller) because the current ISYS provided by (or injected into) the power grid is abruptly interrupted. Consequently, the angular difference between VT and EI is suddenly increased (or decreased) and the terminal voltage phasor changes its direction, as shown in Fig. 2(b). Analyzing such phenomenon in the time-domain, the instantaneous value of the terminal voltage jumps to another value and the phase position changes, as depicted in Fig. 3, where the point A indicates the islanding instant. This behavior of the terminal voltage is called vector surge or vector shift. It is possible to verify that

Fig. 2. Internal and terminal voltage phasors: (a) before the opening of circuit breaker and (b) after the opening of circuit breaker.

Fig. 3. Voltage vector surge and vector surge relay cycle-by-cycle measurements.

the cycle duration also changes. Vector surge relays are based on such phenomena [3]. Vector surge relays available in the market measure the duration time of an electrical cycle and start a new measurement at each zero rising crossings of the terminal voltage. The current cycle duration (measured waveform) is compared with the last one (reference cycle). In an islanding situation, the cycle duration is either shorter or longer, depending on if there is excess or deficit of power in the islanded system, as shown in Fig. 3. This variation of the cycle duration results in a proportional variation of the terminal voltage angle
θ, which is the input parameter of vector surge relays. If the variation of the terminal voltage angle exceeds a pre-determined threshold α, a trip signal is immediately sent to the circuit breaker. Usually, vector surge relays allow this threshold to be adjusted in the range from 2◦ to 20◦ [3]. Another important characteristic available in these relays is a block function by minimum terminal voltage. If the terminal voltage drops below an adjustable level threshold Vmin , the trip signal from the vector surge relay is blocked. This is to avoid, for example, the actuation of the vector surge relay during generator start-up or short-circuits. 3. Determination and analysis of the performance curves In this section, the determination and analysis of the detection time versus active power imbalance curves, i.e. the performance curves, are discussed. In this paper, the performance curves are obtained by using repeated dynamic simulations. The preislanding active power imbalance is gradually varied from 1 to 0 pu, referred to the MVA rating of the generator, by changing the generation–load profile in the islanded system. For each active power imbalance level, dynamic simulation is conducted, the detection time is determined once that the relay activation criterion is met and then the curves are plotted. In this work, the network components were represented by three-phase models. Distribution feeders were modeled as series RL impedances. Transformers were modeled using T circuit. The synchronous generators were represented by a sixth-order threephase model in the dq rotor reference frame [6]. The generators were considered equipped with an automatic voltage regulator, which was represented by the IEEE-Type 1 model. The mechanical power was considered constant, i.e. the primer mover and

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Fig. 4. Algorithm implemented to represent vector surge relays.

governor effects were neglected, because the simulation interval is short (0.5 s). Since load characteristics can have a significant impact on the power imbalance after islanding, the exponential voltage-dependent load model presented in ref. [7] was used. The vector surge relays were simulated as follows. The generator terminal voltage angle θ is determined in each integration step. Moreover, a comparative terminal voltage angle θ 0 is computed and updated in the beginning of each cycle, i.e. it is updated cycle-by-cycle. The absolute variation between these two angles,
θ = ||θ − θ 0 ||, is calculated in each integration step and compared with the angle threshold α. Additionally, the rms value of the terminal voltage is also determined in each integration step. If the angle variation
θ is larger than the relay setting α and the magnitude of the terminal voltage is larger than the adjusted minimum voltage Vmin , the vector surge relay immediately sends a trip signal to the generator circuit breaker. The algorithm can be better understood through Fig. 4. In this figure, the calculation process of the angle variation considering two complete electrical cycles and adopting an integration step equal to 5.56 ms (third part of one electrical cycle in 60 Hz systems) is shown. In this figure, it is considered that the islanding situation occurred at the beginning of the first cycle. Fig. 5 shows the single-line diagram of the network used in this paper. It comprises a 132 kV, 60 Hz, subtransmission system with short-circuit level of 1500 MVA, represented by a Th´evenin equivalent (Sub), which feeds a 33 kV distribution system through a 132 kV/33 kV,
/Yg, transformer. In this system, there is one 30 MW synchronous generator (SG) connected at bus 5, which is connected to the network through one 33 kV/0.69 kV,
/Yg, transformer. In all presented cases, the islanding situation was simulated by opening the circuit breaker CB at bus 2 at t = 0.25 s, which remained open during the rest of the simulation. Therefore, the

Fig. 5. Single-line diagram of the test system 1.

Fig. 6. Performance curves for different relay settings.

initial active power imbalance in the islanded system was equal to the active power provided by the substation at the islanding moment. The total simulation time was 0.75 s. Therefore, if the vector surge relay VSR installed at bus 5 did not detect the islanding condition until 0.5 s after opening of the circuit breaker CB, it was considered that the device was inoperative for this case. Different power imbalance scenarios were created by varying either the generator output or the total system load. Several detection time versus active power imbalance curves for the test system and different relay settings are shown in Fig. 6. These curves were obtained by varying the active power injected by the generator from 0 to 30 MW and keeping the loads constant, as shown in Fig. 5. Consequently, after opening of the circuit breaker CB, there is a deficit of active power in the islanded system. For each power imbalance level, dynamic simulation was conducted to determine the detection time. There is a family of curves, each one corresponding to a different relay setting α. It can be observed that when the power imbalance decreases the detection time increases. The increase is almost

Fig. 7. Concept of critical active power imbalance level.

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exponential when the power mismatch is small. This is reasonable because it takes longer for the relay to detect a small power imbalance. Such curves can be employed to assess the performance of vector surge relays systematically. As an example, assume that the required detection time is 200 ms and the relay setting is 5◦ . In this case, one can draw a horizontal line of 200 ms as shown in Fig. 7. The active power imbalance level in the crossing point between the horizontal line and the relay curve is the minimum active power imbalance required for the vector surge relay to trip the generator within 200 ms. In this case, the active power imbalance level at this point is equal to 27%. Thus, if the islanded system has a power imbalance level higher than 27%, the relay would take less than 200 ms to detect the islanding condition. So the relay can be used with confidence. On the other hand, the relay would take longer than 200 ms to operate if the power imbalanced level is lower than 27%. Consequently, the relay is not suitable for such cases. In this paper, such an active power threshold is called critical active power imbalance level or simply critical power imbalance. 4. Performance characteristics of vector surge relays In this section, the main factors affecting the performance characteristics of vector surge relays are investigated using the performance curves. The factors investigated are voltagedependent loads, load power factor, inertia constant of the generator, generator excitation system control mode, feeder length and R/X ratio as well as multi-distributed generators. Excepting the cases where the impact of voltage-dependent loads and multigenerators are analyzed, the active components of the loads were represented by constant current model and the reactive components were represented by constant impedance model as recommended in ref. [7]. 4.1. Voltage-dependent loads Since the nodal voltages change after islanding, voltagedependent loads affect the dynamic behavior of the active power imbalance in the islanded system. Thus, typical constant impedance, constant current and constant power loads are analyzed in this section. Moreover, the impact of voltage-dependent loads on the performance of vector surge relays will depend on if there is deficit or excess of active and reactive power in the islanded system. Based on these facts, it is necessary to analyze the following four different situations: • Case (a): There is deficit of active and reactive power in the islanded system. • Case (b): There is excess of active power and deficit of reactive power in the islanded system. • Case (c): There is excess of active and reactive power in the islanded system. • Case (d): There is deficit of active power and excess of reactive power in the islanded system.

Fig. 8. Relay performance curves as affected by voltage-dependent loads— relays setting = 10◦ : (a) deficit of reactive power and (b) excess of reactive power.

The performance curves for different types of loads and deficit of reactive power in the islanded system are shown in Fig. 8(a) considering that the relay setting is 10◦ . The cases of active power deficit were simulated maintaining constant the loads and varying the generation from 0 to 30 MW. Whereas the cases of active power excess were obtained keeping constant the generation at 30 MW and varying the total active power load from 0 to 30 MW without changing the load power factor. In these cases, the generator exciter was controlled to keep terminal voltage at 1 pu, as a consequence, there is deficit of reactive power in the islanded system. As expected, it can be seen that the type of load has much influence on the performance of the relays. In this situation, deficit of reactive power, the most conservative case, i.e. the case in which the critical active power imbalance assumes the highest value, occurs when the loads are constant impedance type and there is deficit of active power in the islanded system. On the other hand, the most optimistic case, i.e. the case in which the critical active power imbalance

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Fig. 9. Most optimistic cases vs. most conservative cases—case with deficit of reactive power in the islanded system.

assumes the lowest value, is obtained when the loads are constant impedance type and there is excess of active power in the islanded system. In the case of constant power loads, there is no difference between the cases with deficit and excess of active power. The critical active power imbalances for the most conservative and optimistic cases and different relay settings are shown in Fig. 9, which were obtained considering that the required detection time is 200 ms. It can be observed that if the loads are impedance constant type and the relay setting is 2◦ , then the critical active power imbalance will vary from 2.5 to 18.0%. The cases with excess of reactive power in the islanded system are presented in Fig. 8(b). In these cases, the generator exciter was controlled to keep the generator working at 0.90 capacitive power factor. The situations of excess and deficit of active power were simulated as discussed in the previous cases. The results are contrary to the previous cases, i.e. the most conservative case can be related to the situation with excess of active power and the most optimistic case is related to the situation with deficit of active power. The impact of voltage-dependent loads on the performance of vector surge relays is explained in the sequence. The dynamic behavior of the total active power load of the system shown in Fig. 5 considering different types of loads and sceneries of pre-islanding reactive power imbalance is presented in Fig. 10. In this figure, the system becomes islanded at t = 0.25 s. In Fig. 10(a), the total active power load before the islanding is 30 MW and the generator is injecting 20 MW into the network. In this case, the generator exciter is controlled to keep terminal voltage constant at 1 pu. Thus, the generator is injecting 7.9 MVAr into the network and the rest of the reactive power consumed by the system is supplied by the substation (3.9 MVAr). In this situation, after the islanding, the nodal voltages decrease due to lack of reactive power, although the generator increases the reactive power injected after islanding. Consequently, in the case of constant current and constant impedance loads, the total active power load in the islanded system decreases after islanding. The largest variation can be related to constant impedance loads. In Fig. 10(b), the total active power load before the islanding is

Fig. 10. Dynamic behavior of the active power load during islanding: (a) deficit of reactive power and (b) excess of reactive power.

24 MW and the generator is injecting 30 MW into the network. In this case, the generator exciter is controlled to force the generator to operate at 0.90 capacitive power factor. Thus, before the islanding, the generator is injecting 14.5 MVAr into the network and the substation is consuming 3.4 MVAr. Therefore, there is excess of reactive power in the islanded system. Consequently, the nodal voltages increase after the islanding; as a result, in the case of constant current and constant impedance loads, the total active power load in the islanded system increases after the islanding. Again, the largest variation can be related to constant impedance loads. The impacts of the possible combinations of active and reactive power in the islanded system (Cases a–d) on the relay performance are discussed below. In the case of active and reactive power deficit (Case a), the total active power load decreases after islanding due to nodal voltage reduction and such fact decreases the active power imbalance in the islanded system. Consequently, vector surge

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relays will take longer to detect the islanding situation. On the other hand, in the case of active power excess and reactive power deficit (Case b), the active power load reduction increases the active power imbalance in the islanded system, so that vector surge relays will detect the islanding situation faster. For the same reasons, if there is excess of reactive and active power in the islanded systems (Case c), the active power load increases after islanding and the active power imbalance decreases, such fact makes more difficult to detect the islanding. Finally, if there is deficit of active power and excess of reactive power (Case d), the total active power load increases after the islanding, consequently, the active power imbalance also increases and the relay can detect the islanding situation faster. In the case of constant power loads, there is no difference if there is deficit or excess of active and reactive power in the islanded system, since the active power imbalance will be practically constant, neglecting losses. These important results show that utility engineers must analyze the most conservative cases during studies of vector surge relays, because it is not possible to know if there will be excess or deficit of active and reactive power in the islanded system. Typically, such cases are: • There is deficit of active and reactive power in the islanded system and loads are constant impedance type. • There is excess of active and reactive power in the islanded system and loads are constant impedance type. In the next cases, excepting the cases where multi-generators are analyzed, there is deficit of reactive and active power in the islanded system. These cases were obtained by varying the active power injected by the generator from 0 to 30 MW and keeping the loads constant, as shown in Fig. 5. Moreover, the active power loads were represented by constant current models and reactive power loads were represented by constant impedance models, as recommended in ref. [7]. Although many other scenarios were also simulated, such cases showed to be enough representative to analyze the main technical factors affecting the performance of vector surge relays.

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Fig. 11. Relay performance curves as affected by load power factor.

4.3. Inertia constant of generator The impact of the machine inertia constant (H) on the relay performance is investigated in this section by using the test system 1. The original machine has an inertia constant equal to 1.5 s. In Fig. 12, the performance curves were obtained considering the inertia constant equal to 0.5, 1.0 and 1.5 s, respectively, and the relay setting equal to 10◦ . It can be seen that the inertia constant has a huge influence on the performance curves. Moreover, the larger the inertia constant is, the larger the critical power imbalance level is for the same detection time requirement and relay setting. Such fact is due to the energy stored in the rotational mass of the machine, which is proportional to the value of the inertia constant. Consequently, a generator with a large inertia constant will take more time to cause frequency deviation than a generator with a small inertia constant. The critical power imbalances for a 200 ms detection time requirement and different relay settings and inertia constant values are compared

4.2. Load power factor The impact of the load power factor on the performance curves was also investigated. The power factor of the loads was varied while the active power was kept constant. The results are shown in Fig. 11 for relay setting of 5◦ , 10◦ and 15◦ . The figure reveals that the load power factor has little influence on the performance of vector surge relays. The slight difference among the curves can be explained by the following fact: as there is deficit of reactive and active power in the islanded systems, the smaller the power factor is, the larger the reduction of the voltage profile is after islanding. As the loads have constant current characteristics, the reduction of the active power consumed is larger in this case. Consequently, the power imbalance after opening of the circuit breaker decreases and the relay takes more time to detect the islanding situation, however, the difference is small.

Fig. 12. Relay performance curves as affected by the inertia constant of the generator (H)—relay setting equal to 10◦ .

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Fig. 13. Critical power imbalance as affected by the inertia constant of the generator.

in Fig. 13. The results show that vector surge relays are more effective when employed to protect small generators. 4.4. Excitation system control mode A distributed synchronous generator typically has different modes of controlling its excitation system. One is to maintain constant terminal voltage (voltage control mode) and another one is to maintain constant power factor (power factor control mode) [3]. In the power factor control mode, in this section, the generator was controlled to keep unitary power factor operation. The performance curves for the two control modes are compared in Fig. 14. In these cases, there is deficit of reactive and active power in the islanded system. It is found that the critical power imbalance is larger if the excitation system is controlled by power factor rather than by voltage. This is due to the different dynamic behavior of the constant current active

Fig. 14. Relay performance curves as affected by excitation system control modes.

Fig. 15. Dynamic behavior of total active power load during islanding considering different excitation system control modes (synchronous generator injecting 20 MW).

loads under distinct control modes. The dynamic behavior of the active power load for different control modes is shown in Fig. 15 when the generator is injecting 20 MW. It can be seen that the load reduction is larger when the generator is operated at unitary power factor. As a result, the active power imbalance reduction in this case is larger too, becoming more difficult to detect the islanding situation. For the same reason, the case in which there is excess of active power and deficit of reactive power after islanding showed that the critical power imbalance is smaller in power factor control mode than that obtained in the voltage control mode. It was also found that if the load is modeled as constant power load, there is no difference between the two control modes. 4.5. Feeder length and X/R ratio The influence of the feeder length on the relay performance is verified in this section. In this case, the length of the feeder was varied by multiplying the line impedance by a factor K. K was selected to be 0.5, 1.0 and 2.0. The results are shown in Fig. 16 for relay setting of 5◦ , 10◦ and 15◦ . It can be seen that feeder length has little influence on the relay characteristics. There is a slight tendency for the critical power imbalance to increase when the feeder length increases. This is caused by the higher reduction of the nodal voltages when a feeder is longer because there is deficit of reactive power in the islanded system. Such voltage reduction leads to a diminution of the power imbalance in the islanded system, becoming more difficult to detect the islanding situation, however, the difference is very small. The impact of the feeder X/R ratio was also investigated. The original system has a X/R ratio of 4.30. The simulation results with a X/R ratio of 2.15 are presented in Fig. 17 for relay setting of 5◦ , 10◦ and 15◦ . In this study, the X/R ratio was modified considering two different cases. In the first case, the X/R ratio was reduced by halving the X value. This case is identified as “X/2”

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4.6. Multiple distributed generators

Fig. 16. Relay performance curves as affected by feeder length.

in the figure. In the second case, X/R was modified by doubling the R value, which is labeled as “R*2” in the figure. It can be seen that the X/R ratio has little influence on the performance curves.

Fig. 17. Relay performance curves as affected by feeder X/R relation.

The distribution system presented in Fig. 18 was utilized to analyze cases with multiple distributed generators. This system is composed by a 138 kV, 60 Hz, subtransmission system with short-circuit level of 1000 MVA, which feeds a 25 kV distribution system through a 138 kV/25 kV, Yg/
, transformer. In this system, there are two synchronous generators with capacity of 4.5 and 6 MVA, respectively, connected at bus 7 and 9, which are connected to network through 25 kV/2.4 kV, Yg/
, transformers. In this case, there are two sets of vector surge relays and circuit breakers: one at bus 7 (VSR1 + CB1 ) and another one at bus 9 (VSR2 + CB2 ). It is important to mention that was considered a delay of 0.05 s between the instant of successful islanding detection and the instant of circuit breaker opening [6]. The system became islanded by opening the circuit breaker CB at bus 2. In multi-distributed generator case, results showed that it is important to analyze the impacts considering situations in which there is deficit and excess of active power and, simultaneously, deficit of reactive power in the islanded system. Moreover, the loads were represented by constant impedance models because this type of load leads to the extreme behavior of vector surge relays. For the cases with deficit of active power after islanding, the loads were maintained constant as shown in Fig. 18 and the active power injected by generator 2 (SG2 ) was kept constant at 5.5 MW. Then, the active power injected by generator 1 (SG1 ) was varied from 0.2 to 4.5 MW to achieve different power imbalance levels. The results are shown in Fig. 19. In this figure, only the performance curves associated with VSR1 are shown. The performance curves with only VSR1 in operation are used as a reference for comparison. These curves are labeled as “no VSR2 ” in the figure. The curves for the cases in which the VSR1 relay setting is equal to 5◦ , 10◦ and 15◦ are shown. These reference cases are then compared with the cases with two relays (VSR1 and VSR2 ) in operation, where the VSR2 setting is fixed at 5◦ and VSR1 setting is again varied. Such curves are labeled as “VSR2 = 5◦ ”. Ideally, one wishes to see that the relay curve, which is VSR1 in this case, will not be affected by the presence of another relay, which is VSR2 . It can be seen from the figure, however, that when there is another relay in the system, the performance curves of the VSR1 are much influenced when this relay is set equal to 10◦ and 15◦ . On the other hand, the curve obtained with VSR1 relay setting equal to 5◦

Fig. 18. Single-line diagram of the test system 2.

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than 5◦ . If the VSR1 setting is equal to 10◦ , the relay has a more sensitive response due to the presence of the VSR2 . This is because it acts at the instant that the SG2 is disconnected. Such event causes perturbations in the network, which can be large enough to activate VSR1 . On the other hand, if the VSR1 setting is equal to 15◦ , the presence of the second vector surge relay will increase the critical power imbalance level from 54.1 to 90.1%, making it difficult for VSR1 to detect the island condition. This is because there is excess of active power after islanding. Thus, when the generator SG2 is tripped before the generator SG1 due to a tighter VSR2 relay setting, the power imbalance decreases considerably. It makes the detection of islanding much more difficult for the VSR1 . In summary, the multi-distributed generators case study results reveal that the relay characteristics can interfere with each other, making the prediction of relay performance very difficult. The critical power imbalances for the cases analyzed above are shown in Fig. 21. It can be observed that the Fig. 19. Relay performance curves as affected by multi-distributed generators (deficit of reactive and active power).

is not affected. This is because both relays have the same setting. Consequently, there is almost no interference between the relays. The conclusion drawn from the results is the following: if there is a deficit of reactive and active power in the islanded system, a tight setting for one relay can reduce the critical power imbalance level related to the other relay. This occurs because the trip of the first generator will increase the power imbalance level in the islanded system, leading to the other relay to operate in a shorter time. For the case in which there is excess of active power after islanding, the simulation was conducted by maintaining constant power for both generators at 6 and 4.5 MW. Then, the total system active power load was varied from 10.5 to approximately 0 MW to create different power imbalance scenarios. The results are shown in Fig. 20, where only the performance curves related to VSR1 are presented. The results also suggest that there is interference between the two relays when VSR1 setting is greater

Fig. 20. Relay performance curves as affected by multi-distributed generators (deficit of reactive power and excess of active power).

Fig. 21. Influence of multi-vector surge relays on the critical power imbalance: (a) deficit of reactive and active power and (b) deficit of reactive power and excess of active power.

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Table 1 Summary of the investigations concerning the vector surge relay performance Case investigated

Load model

Description

Results

The influence of voltage-dependent loads

Constant power, constant current and constant impedance

Four cases were investigate for each load model: • Case (a): deficit of active and reactive power • Case (b): excess of active power and deficit of reactive power • Case (c): excess of active and reactive power • Case (d): deficit of active power and excess of reactive power

Voltage-dependent loads have huge influence on the relay performance Most conservative cases: • Case (a) and constant impedance loads • Case (c) and constant impedance loads Most optimistic cases: • Case (b) and constant impedance loads • Case (d) and constant impedance loads

The influence of load power factor

The influence of the inertia constant of the generator

The influence of the excitation system control modes

Active component: constant current type Reactive component: constant impedance type Active component: constant current type Reactive component: constant impedance type

Deficit of active and reactive power has been considered Load power factors tested: 0.80, 0.90 and 0.95 Deficit of active and reactive power has been considered Values of the inertia constant of the generator: 0.5, 1 and 1.5

Load power factor has little influence on the relay performance

Active component: constant current type

Deficit of active and reactive power has been considered and two control modes of the excitation system were investigated: • Voltage control: set point equal to 1 pu • Power factor control: set point equal to 1

The control mode of the excitation system has huge influence on the relay performance. Under power factor control mode, the critical power imbalances are larger than those obtained under voltage control mode

Reactive component: constant impedance type

The inertia constant of the generator has huge influence on the relay performance. In fact, the larger the inertia constant, the larger the critical power imbalance

The influence of the feeder length

Active component: constant current type Reactive component: constant impedance type

Deficit of active and reactive power has been considered. The feeder length has been multiplied by 0.5, 1 and 2

Variations on the feeder length have little influence on the relay performance

The influence of X/R ratio

Active component: constant current type Reactive component: constant impedance type

Deficit of active and reactive power has been considered. The feeder X/R ration length has assumed the following values: 4.3, 2.1 (by halving X) and 2.1 (by doubling R)

The ration X/R has little influence on the relay performance

presence of the second relay can decrease or increase the critical power imbalance of the first relay.

5. Conclusions This paper has presented an extensive investigation on the performance characteristics of the vector surge relays employed to detect islanding of distributed synchronous generators. The proposed detection time versus active power imbalance curves proved to be a useful tool to assist the evaluation of the relay performance. The investigation on the relay performance has been done through the analysis of various cases, which can be summarized in Tables 1 and 2, as well as the main results. Based on the results of the investigation, the main conclusions are summarized below:

• The relay performance can be quite different depending on if there is excess or deficit of active and reactive power in the islanded system. The basic factor behind the different responses is the voltage-dependent characteristics of the loads. These important results show that utility engineers must analyze the most conservative cases during studies of vector surge relays. Typically, such cases are characterized by: - There is deficit of active and reactive power in the islanded system and loads are constant impedance type. - There is excess of active and reactive power in the islanded system and loads are constant impedance type. • The main factors affecting the performance of vector surge relays are inertia constant of the generator, load type and the excitation system control mode. The excitation control

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Table 2 Influence of multiple distributed generators on the vector surge relay performance (see Section 4.6) Case investigated

Load model

VSR2 setting (◦ )

VSR1 setting (◦ )

Results

Deficit of active and reactive power

Constant impedance

5

5 10

No interferences between the relays After VSR2 operation, the disconnection of SG2 causes the active power imbalance rising and, consequently, accelerates the VSR1 operation After VSR2 operation, the disconnection of SG2 causes the active power imbalance rising and, consequently, accelerates the VSR1 operation

15

Excess of active and deficit of reactive power

Constant impedance

5

5 10 15

mode affects the performance through the voltage-dependent characteristics of the loads. • The feeder length and X/R ratio as well as the load power factor have little influence on the performance of vector surge relays. • When there are multiple vector surge relays with different settings in an islanded network, there is a good chance that the relays will interfere with each other, leading to very difficult-to-predict system responses to islanding conditions. Although the results presented in this paper are based on two test systems, studies have also been conducted in more complex systems and the results obtained were quite similar.

No interferences between the relays After VSR2 operation, the disturbances cause large transients that provoke VSR1 actuation After VSR2 operation, the disconnection of SG2 causes the active power imbalance reduction and, consequently, delays the VSR1 operation

References [1] CIGRE Working Group 37.23, Impact of Increasing Contribution of Dispersed Generation on the Power System, CIGRE, Technical Report, 1999. [2] CIRED Working Goup 4, Dispersed Generation, CIRED, Technical Report, June (available: http://www.cired.be). [3] N. Jenkins, R. Allan, P. Crossley, D. Kirschen, G. Strbac, Embedded Generation, first ed., Institute of Electrical Engineers, 2000. [4] IEEE Standard P1547, IEEE Standard for Interconnecting Distributed Resources with Electric Power Systems, IEEE, Standards Coordinating Committee 21, 2003. [5] Electricity Association, G59/1 Recommendations for the Connection of Embedded Generating Plant to the Regional Electricity Companies Distribution Systems, Electricity Association Std., 1991. [6] P. Kundur, Power System Stability and Control, McGraw-Hill Inc., New York, 1994. [7] IEEE Task Force, Load representation for dynamic performance analysis, IEEE Trans. Power Deliv. 8 (1) (1993) 472–482.