IEEE TRANSACTIONS ON POWER DELIVERY, VOL. 23, NO. 3, JULY 2008
1581
Abstract— The presence of synchronous and induction generators has a positive effect on the retained voltage (the lowest rms voltage during the event) during voltage dips in high voltage networks. The impact of converter-connected distributed-generation
(DG) units has been reported to be negligible, as most converters operate at unity power factor, and the currents injected in the grid are limited to the nominal current of the converter. However, the impact of DG units on the distorted grid voltage is strongly dependent on the voltage level, and thus the grid impedance, of the concerned grid. This paper investigates and compares the effects of converter-based DG units, synchronous and asynchronous generators on the retained voltage during voltage dips in low voltage distribution grids.
Index Terms— Distributed generation (DG), low voltage grids, mitigation, retained voltage, voltage dips.
I. I NTRODUCTION
T HE GROWING interest in environmental issues, combined with the progress of technologies to connect renewable energy sources to the grid and the liberalization of the energy market have led to a growing share of grid-connected distributed generation systems. The primary energy sources most often used in small-scale applications are wind, solar power, small combined heat and power units, fuel cells and hydro power. In spite of the growing number of distributed-generation (DG) units, their contribution of power delivered to the utility grid remains small, as compared to the power injected by the large centralized power plants.
Therefore, the behavior of DG units subjected to voltage dips has not received much attention in the past. Moreover, many grid operators demand the immediate shutdown of DG units in case of grid disturbances as prerequisite for grid connection. Interconnection of DG to electrical power systems has been discussed in [1]. However, as the power generated by DG units increases, this behavior stresses the utility grid and could cause power unbalance, which may turn into instability. In order to
Manuscript received April 11, 2007; revised June 21, 2007. This work was supported in part by the Research Programme of the Research Foundation—Flanders (FWO) and in part by the Institute for the Promotion of Innovation through Science and Technology in Flanders. Paper no.
TPWRD-00195-2007.
B. Renders, K. De Gussemé, and L. Vandevelde are with the Electrical Energy
Laboratory (EELAB), Department of Electrical Energy, Systems and Automation (EESA), Ghent University, Ghent 9000, Belgium.
W. R. Ryckaert is with the Department Industrieel Ingenieur, Katholieke
Hogeschool Sint-Lieven, Ghent 9000, Belgium.
K. Stockman is with the Department Provinciale Industriële Hogeschool,
Hogeschool West-Vlaanderen, Kortrijk 8500, Belgium.
M. H. J. Bollen is with the STRI AB, Ludvika 77180, Sweden. He is also with Luleå University of Technology, Skellefteå 931 87, Sweden.
Digital Object Identifier 10.1109/TPWRD.2007.916162
achieve a sustainable grid reliability combined with large penetration of DG, some grid operators already require voltage-dip ride-through capability [2].
Recently, DG applications have been used to improve the power quality of the utility grid. The effect of DG units on the frequency of interruptions [3], [4] and their mitigating influence on the severity of voltage dips [5]–[8] were investigated. DG units may yield additional power quality and an improved reliability. These benefits are rarely taken into consideration for installation of DG units. However, if DG units reduce the consequences of voltage dips [9], industrial customers would be more inclined to install DG units.
In this paper, the behavior of grid-coupled DG units during voltage dips in low voltage distribution grids will be investigated. The impact of DG units on the retained grid voltage (the lowest rms voltage during the event) is strongly dependent on the voltage level, and thus the grid impedance, of the concerned grid. This paper will focus on small-scaled DG units connected to the low voltage distribution grid. Three types of DG units will be investigated: asynchronous generators, synchronous generators and converter-connected units.
The positive impact during dips of asynchronous and synchronous machines connected to the grid on medium to high voltage levels is well-known. The machines tend to inject reactive power into the utility grid due to the voltage dip, thus increasing the retained voltage during the dip. The impact of commercially available converter-connected DG units is reported to be negligible, as most converters operate at unity power factor, and the currents injected in the grid are limited to the nominal current of the converter [7], [8]. If converter-connected DG units do inject reactive power in the grid, they are able to mitigate grid voltage dips [10]. However, the strong relation between reactive power and voltage is not valid in low-voltage distribution grids.
Synchronous, asynchronous and converter-based DG units will show a different fault current contribution [11]. As the voltage will strongly depend on the active power injected in the grid, the impact of asynchronous machines, synchronous machines and power-factor correcting converters should be reinvestigated.
The presence of a DG unit on the distribution feeder will mitigate the voltage dips as experienced by the load connected to the equipment terminals. The effects on the voltage during the dip will be dependent on the type of distributed generation. In this paper, the comparison is made between asynchronous and synchronous generators and converter-based DG units.
II. V OLTAGE D IP A NALYSIS
Voltage dips originate from motor starting, transformer energizing and short circuits in the transmission system. In this
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1582 IEEE TRANSACTIONS ON POWER DELIVERY, VOL. 23, NO. 3, JULY 2008
Fig. 1. Voltage divider model.
paper, the analysis is based on voltage dips caused by short circuits.
In order to determine the voltage at the equipment terminals in radial systems, we can use the voltage divider model of Fig. 1.
This model consists of the source impedance at the point of common coupling (PCC) and the impedance between the
PCC and the fault. In this model all loads are initially supposed to be of the constant impedance type. This allows to include the contribution of the loads into the source impedance. The voltage at the PCC is thus given by
Fig. 2. Dip types with a magnitude of 0.7 p.u.
(1)
This expression allows to calculate the dip magnitude and the phase angle jump for the PCC.
This model can be extended to study the effect of DG units on voltage dips. In Fig. 1, another branch is added to the PCC.
This branch consists of the impedance , representing the impedance between the PCC and the equipment terminals. Note that this impedance can also include transformation to lower voltage levels. The voltage at the equipment terminals will be strongly dependent on the behavior of the connected DG units, represented in the scheme by a voltage source and an impedance thus given by
. The voltage at the equipment terminals is
(2)
Fig. 3. Topology of the full-bridge bidirectional converter.
III. E FFECT OF V OLTAGE D IPS ON THE DG U NIT
To be able to model the DG units during dips as a voltage source and an impedance , their behavior during dips must be studied. The behavior of synchronous and asynchronous machines during voltage dips and the corresponding models is well-known, therefore only the behavior of converter-connected DG units is described below. To keep the results as general as possible a full-bridge bidirectional topology is used to represent converter-connected DG units.
The behavior of the converter during voltage dips is dependent on the implemented control strategy. The control strategy implemented on the converter described in this paper improves the voltage-dip ride-through capability of the DG unit [13].
This analysis based on the single-phase equivalent is strictly speaking only valid for three-phase faults. The impedances used are the positive-sequence values. For unsymmetrical phenomena, we need to replace the impedances and voltage sources by their respective symmetrical components value.
An extensive analysis was carried out in [7], [12], where the voltage at the PCC is classified into seven different types. These types are depicted in Fig. 2 for a retained voltage magnitude of
0.7 p.u.
As in most cases the voltage at the PCC is only slightly affected by the behavior of the DG units at the equipment terminals, the voltage at the PCC can be represented by a controlled voltage source. The voltage dips subjected to the PCC will be limited to the types described in [7]. To verify the influence of small-scaled DG units connected to the distribution network at low voltages, the system to be studied can be limited to the low-voltage feeder. The DG units are supposed to be uniformly distributed among the three phases.
A. System Description
The topology of the full-bridge ac–dc bidirectional converter is depicted in Fig. 3. The converter consists of an EMI-filter
(represented by the capacitor ) on the ac-side of the converter, and a boost-type full-bridge converter with two input inductors
, switches to , and a buffer capacitor at the dc-side of the converter. The converter is controlled by means of a digital signal processor (DSP).
The measurements necessary for the control of the converter are the inductor current , grid voltage , and bus voltage
. These analog control variables are converted into digital quantities and are used by the digital controller to calculate the duty-ratio . The pulsewidth-modulated (PWM) signals are calculated based on this duty ratio and are presented to the switches of the full-bridge converter.
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RENDERS et al.
: DISTRIBUTED GENERATION FOR MITIGATING VOLTAGE DIPS 1583 the programmable damping resistance . This conductance prescribes the magnitude of the harmonic current components in the inductor current of the converter and is chosen to keep these current components limited while retaining the maximal damping potential. This control strategy was designed to damp harmonic oscillations in the utility grid [15].
Fig. 4. Control strategy for a grid-connected converter for DG units.
The behavior of the converter during grid voltage dips is mainly dependent on the converter control. In order to obtain a better voltage dip ride-through capability, we will utilize the controller with damping resistance [13]. This controller increases the power injected in the grid during the voltage dip.
This allows to prevent premature shutdown of the converter due to an excessive bus voltage.
Most commercial available grid-connected converters use a phase locked loop (PLL) and try to shape the injected line currents as perfect sinewaves [14]. The corresponding control algorithm is depicted in Fig. 4 (black lines only). We will refer to these types of converters as sinewave converters.
The control scheme depicted in black uses two controllers: a bus voltage controller and an inductor current controller.
The bus voltage controller obtains a constant bus voltage by changing the value of the fundamental input conductance .
This prescribes the amplitude of the desired inductor current and thus the amount of fundamental power exchanged with the grid. The reference value for the fundamental inductor current is the product of the emulated fundamental conductance and a sinusoidal reference signal
(3)
The phase of the sinusoidal reference signal is locked to the phase of the fundamental component of the mains voltage by using a standard phase locked loop.
The control strategy with damping resistance is based on the same operation principle. However, an extra signal is added to the reference value for the inductor current of (3)
(4)
The last term of (4) is represented in gray in Fig. 4.
The first term of this equation can be interpreted as the steady-state value of the fundamental component of the inductor current. This term is adapted by the bus-voltage controller in order to balance the power exchanged with the utility grid. Since the voltage controller is slow, is slowly varying. The second term of the equation is swiftly varying, as it will react instantaneously on every deviation of the grid voltage from its steady-state value . The current originating from voltage disturbances is determined by
B. Voltage Dips
For single-phase appliances grid-voltage dips can be represented by a retained voltage and a phase-angle jump . For the point-on-wave, the worst case is considered, the voltage dips initiate at maximum voltage.
As can be seen from (3) and (4), the utilized control strategy will behave differently from the “classical” control strategy when subject to grid voltage dips. The sinewave controller will not react instantaneously, so the injected current will not change due to the voltage dip (3). After one or two grid periods, the bus voltage controller will start to increase the injected current in order to restore the disturbed power balance between the ac and dc side of the converter. In this paper, the power generated at the dc side of the converter is supposed to be constant.
The controller with programmable damping resistance will react instantaneously to voltage dips. Since the reference value for the grid current contains a term dependent on deviations of the grid voltage from its steady state value (4), the grid current will increase proportionally to and to the decrease of the grid voltage. The power injected in the grid during the dip is larger than the power injected in the grid just before dip initiation. Eventually, the bus voltage controller will decrease the grid current again in order to restore the power balance.
The behavior of both controllers is depicted in Fig. 5 for a voltage dip of 30% lasting 2 grid periods. The magnitude of the inductor current of the sinewave converter (depicted as a dotted black line) will only increase slowly due to the action of the bus voltage controller. Due to the sudden voltage change at the start and at the end of the voltage dip, a perturbation of the inductor current can be discerned. This perturbation is present in the inductor current of the converter with damping algorithm
(full black line) too, but is hidden due to the change of the desired inductor current .
The reaction of the converter to phase-angle jumps is dependent on the quickness of response of the PLL. Since a standard
PLL is used, the reaction is supposed to be slow in comparison with the length of the voltage dips. Equations (3) and (4) and
Fig. 5 show that the phase angle between the grid voltage and the injected grid current is zero in steady state. However, during a grid voltage dip with phase-angle jump, the sinusoidal reference signal will be leading or lagging the grid voltage, dependent on the sign of the phase-angle jump. Therefore, the injected grid current will also lead or lag the grid voltage with an angle equal to the phase-angle jump. If the voltage dip lasts for several net periods the PLL will start to decrease the phase angle in order to obtain a unity power factor. This phenomenon is depicted in
Fig. 6. At voltage dip initiation, the power injected in the utility grid is reduced due to the decreased power factor. The second term of (4) is proportional to the missing voltage, and results in an additional decrease of the power factor. Nevertheless, due
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1584 IEEE TRANSACTIONS ON POWER DELIVERY, VOL. 23, NO. 3, JULY 2008
A. Converter-Connected DG
The converter controlled by the damping control strategy reacts according to (4). Based on this equation and the proposed model
(5)
Fig. 5. Grid voltage and grid currents during a 30% voltage dip. Dashed gray line: grid voltage, full black line: inductor current of the converter with programmable damping resistance, dotted black line: inductor current of the sinewave converter.
Fig. 6. Grid voltage and grid currents during a 30% voltage dip with a phase angle jump of
+45
. Dashed gray line: grid voltage, full black line: inductor current of the converter with programmable damping resistance, dotted black line: inductor current of the sinewave converter.
to the instantaneous increase of the grid current the total transferred power is larger as compared to the power transferred with the “classical” controller.
This behavior is beneficial for the voltage dip ride-through capability, as the bus voltage is kept lower compared to the sinewave controller. This prevents shutdown of the converter due to excessive bus voltage [13].
keeping in mind that the conductance is negative when injecting power into the grid according to the definition used in
Section III. The phase angle between the voltage at the PCC and the voltage at the equipment terminals is represented by .
The model allows to investigate two different states of the converter. The converter can be disconnected from the grid, this corresponds with , while p.u. corresponds with the converter in connected state. The parameter allows to represent the power injected in the grid. The power level of the converter can vary between zero and the nominal power of the
DG units, which corresponds with varying between 0 and .
The voltage source is independent of the grid voltage.
At voltage dip initiation, the voltage at the grid side of drops, while remains constant. The current supplied by the converter will thus increase proportionally to the voltage dip according to the voltage divider of Fig. 1. This conclusion matches the behavior of the converter as described in Section III. During the dip the bus voltage controller will decrease the power injected in the grid (increase ) in order to restore the power balance. The voltage will slowly decrease during the voltage dip until a new steady-state is reached.
This model is only accurate if the converter current is not limited. Therefore, two different influences should be verified.
First, the instantaneous increase of the grid current. Second, on a longer time scale, the bus voltage controller will increase the injected current to maintain a constant dc voltage. In both cases, the converter current may not exceed the current limit.
The current limit is larger than the nominal current. In order to reduce the switch losses of the converter, equal to about is chosen
. The maximum permissible increase of the converter current depends on the power level of the converter just before the voltage dip. The lower the power level, the more the current can increase without violating the current limit. The power level can be represented by , the fundamental conductance.
The instantaneous current increase depends on the severity of the voltage dip, represented by the retained voltage of the dip. The peak value of the current during the dip can thus be written as
IV. M ODELLING THE DG B EHAVIOR
Thanks to the behavior of distributed generation systems during voltage dips and the resulting change of the power flow through the low voltage distribution feeder, the voltage at the equipment terminals will be affected by their presence.
In order to quantify the voltage at the equipment terminals based on Fig. 1, the DG units need to be modeled as a voltage source in series with an impedance . This approach is similar to the one used to investigate the effects of induction motors on voltage dips in [7].
with and
(6) p.u. conductances. This equation is plotted in black lines in Fig. 7 for different values of . The maximum current is depicted as a thick black horizontal line at 1.5 p.u.
This current limit is thus only reached during severe voltage dips when the converter is injecting much power into the grid. For example, if the power level of the converter is equal to ,
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: DISTRIBUTED GENERATION FOR MITIGATING VOLTAGE DIPS 1585
The induction generator is modeled by the asynchronous machine block of the Simulink-SimPowerSystems toolbox of
Matlab. The electrical part of the machine is represented by a fourth-order state-space model and the mechanical part by a second-order system. The mechanical power was considered to be constant.
Fig. 7. Peak value of the converter current during dips with increasing dip depth in function of the power level. Black lines: peak value of the current at dip initiation, Dashed gray lines: long time peak value (several net periods after dip initiation) of the inductor current.
C. Synchronous Generator
Synchronous generators can be considered to have fault currents with a rapid decay of the dc offset and a nearly constant ac component [8], [17]. The decay of the dc component is determined by the armature time constant and thus also by the location of the fault. For the simulations presented in this paper, the “far-from-generator-short-circuit” model has been used.
The synchronous generator is modeled using the synchronous machine block of the Simulink-SimPowerSystems toolbox of
Matlab. The electrical part of the machine is represented by a sixth-order state-space model. The model takes into account the dynamics of the stator, field, and damper windings. The prime mover dynamics were neglected, the mechanical power was considered constant. It was assumed that the reactive power of the generator is able to vary between zero and half the active power ( ), in order to keep the terminal voltage as close to its nominal value as possible.
the current will not be limited during all short voltage dips with retained voltage larger than 0.3 p.u.
The long time current increase depends also on the severity of the voltage dip. The current will increase until the power balance is restored. The peak value of the current just before dip initiation is . As the grid voltage drops to , the current is increased by the dc voltage controller to rent will thus be limited if
. The cur-
, for severe voltage dips and a high power level. These results are plotted in Fig. 7 as dashed gray lines. The effect of the bus voltage controller is that the peak current will change from the black towards the dashed gray lines for a certain value of and . The time needed to perform this change is about three grid periods. Whether the peak value of the converter current will increase or decrease is dependent on the value of and .
The majority of the occurring voltage dips are short and deep or long and shallow, as can be concluded based on the scatter diagrams of [16] resulting from an extensive voltage-dip survey.
Considering the fluctuating power level of the renewable energy sources, and the occurrence of the voltage dips, we can conclude that the voltage source model as suggested in (5) will be valid for a large amount of the occurring voltage dips.
B. Asynchronous Generator
The effect of induction generators on balanced faults may be modelled as a voltage source in series with an impedance.
The back-emf is slightly lower than the voltage at the generator terminals in normal operation. When the voltage at the terminals drops upon fault initiation, the back-emf follows with a delay determined by the subtransient time constant of the induction machine [7], [17].
Induction generators have a low impedance to unbalanced voltages and so will draw large currents during asymmetrical voltage dips. Unbalanced currents increase the heating in the generator and impose a torque ripple on the drive train. Excessive unbalanced currents may cause tripping of the induction generator.
V. M ITIGATION OF V OLTAGE D IPS IN LV N ETWORKS
As opposed to the effects of asynchronous and synchronous generators on the retained voltage in medium to high voltage grids [7], the influence of synchronous and asynchronous machines is fairly lower in low voltage grids [18]. The voltage improvement as seen in high voltage grids is the result of an additional injection of reactive power in the grid at dip initiation, combined with the nearly reactive character of the grid impedance. However, in low voltage distribution networks, the grid impedance cannot be represented by a pure reactance. The injected reactive power has a smaller impact on the voltage profile along the distribution feeder.
The influence of converter-connected distributed generation systems on the retained voltage in high voltage networks was reported to be negligible [7], [8]. Indeed, the currents injected in the grid by the DG units are limited to 1 p.u., and most converters do not inject reactive power in the grid. However, in low voltage distribution networks, the voltage drop along the feeder is mainly dependent on the injected active power. The influence of converter-connected DG on the retained rms voltage during dips in low-voltage grids is not negligible.
We consider the voltage dips of Fig. 2 in a 400 V network with a retained magnitude of 0.7 p.u. at the PCC. The voltage dips are caused by a short circuit in the feeding 10 kV grid. The equipment terminals are connected to the 10 kV grid via a 400 kVA 10 kV/400 V transformer and a 800 m long 100 kVA distribution feeder. This represents a Belgian rural distribution network. In the Simulink-SimPowerSystems model of the power system of Fig. 1 the utility grid as seen from the equipment terminals is represented by a three-phase voltage source and a source impedance. This source impedance is chosen according
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1586 IEEE TRANSACTIONS ON POWER DELIVERY, VOL. 23, NO. 3, JULY 2008
TABLE I
S YMMETRICAL C OMPONENTS OF THE V OLTAGE AT THE E QUIPMENT T ERMINALS
D URING V OLTAGE DIP FOR D IFFERENT DG C ONFIGURATIONS drop along the feeder and may even cause voltage rise along the feeder if the power generated by the DG exceeds the power absorbed in the impedance load during the dip. This situation is more likely to occur as the ratio between the actual power injected by the DG and the power absorbed in the impedance load grows and as the voltage dip is more severe.
The increase of the positive-sequence voltage depends on the current injected into the grid by the DG units. By using the common approximation for voltage rise in distribution systems, the following expression is obtained for small voltage rise:
(7) to the European Reference Impedance [19] for low-voltage distribution grids for a customer at the far end of the distribution feeder.
The load (60 kVA of impedance load) connected to the distribution feeder is distributed evenly along the feeder. Large DG units are most likely located close to the low voltage side of the distribution transformer. In the simulation model, the location of the synchronous and asynchronous generator is chosen
200 m from the transformer. For DG units further away from the transformer, the cable or line impedance would increase, but the DG size would most likely be smaller. In the model the converter-based DG units, which are small single-phase units, are equally distributed and located on 150, 350, 600, and 750 m from the transformer.
In order to study the influence of DG units on the distribution feeder during voltage dips, four situations are compared.
In all situations 60 kVA of impedance load is connected to the equipment terminals. In the first situation no DG is connected.
The second, third, and fourth situation, where DG units with an apparent power of 30 kVA are connected, illustrate the influence of asynchronous generators, synchronous generators, and converter-connected distributed generators, respectively. In order to validate the above-made postulation, we will apply the seven different types of grid voltage dips (Fig. 2) to the power system model, and then calculate the change of the voltage along the distribution feeder. To obtain a representative value for this voltage, an average voltage is calculated based on the voltages on ten nodes equally distributed on the distribution feeder. The positive, negative, and zero-sequence components of the average voltage at the equipment terminals for the seven different voltage dips and for the four different situations are represented in Table I.
As can be seen in Table I, the voltage at the equipment terminals is affected by the presence of DG units. Thanks to the fact that the DG units do not decrease the current injected in the grid during voltage dips, in combination with the decrease of the current absorbed in the impedance load, the power flow along the distribution feeder is changed. This decreases the voltage where the feeder impedance and
. As the apparent power of the three
DG units is chosen equal, the voltage drop along the distribution feeder is reduced most with a power factor equal to unity, due to the impedance value of the source impedance ( ).
Converter-based DG units operate at unity power factor before and during the voltage dip. Therefore, the positive-sequence value of the voltage at the equipment terminals is largest for the converter-based DG, followed by the synchronous generator as it injects reactive power in the grid and the smallest value is obtained with the induction generator as it absorbs reactive power.
A comparison between the positive-sequence voltage component of the voltage at the equipment terminals in the four different situations represented in Table I, clearly illustrates this principle.
For asymmetrical dips, the negative-sequence impedance of the DG combined with the negative-sequence voltage component will determine the negative-sequence currents absorbed in the DG units. These currents, combined with the negative-sequence grid impedance, mitigate the negative-sequence voltages at the equipment terminals during the dip. The low impedance value for negative-sequence voltages of induction machines results in large negative-sequence currents. In this simulation, possible tripping of the induction generator is not considered. However, as the negative-sequence impedance of the asynchronous generator is approximately 0.2 p.u., the negative-sequence currents will cause unacceptable heating of the machine, for voltage dips with a large negative-sequence voltage component and a long duration. The synchronous generator has a larger negativesequence impedance, and consequently the negative-sequence voltage is larger as compared to the situation with the induction generator. Converter-connected DG have a large impedance for negative-sequence voltages. This results in smaller negative-sequence currents, and less mitigation of the negative-sequence voltage component.
The effects of the negative-sequence impedance can be illustrated applying a voltage dip of type C to the distribution feeder. The magnitude of the direct, inverse and zero-sequence components of the voltage at the equipment terminals and the line currents of the DG units are shown in Fig. 8. Even with a fairly low negative-sequence voltage (full gray line) the negative-sequence current of the asynchronous machine becomes quite large (dotted gray line). The direct current component
(dotted black line) decreases, but increases again after two grid periods. The negative-sequence component of the current of the
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RENDERS et al.
: DISTRIBUTED GENERATION FOR MITIGATING VOLTAGE DIPS 1587
Fig. 8. Amplitude of direct (black) and inverse (gray) components of the voltage at the equipment terminals during a voltage dip of type C and amplitude of direct (black) and inverse (gray) components of the line current of converter-connected DG units (full lines), asynchronous generator (dotted lines) and synchronous generator (dashed lines).
synchronous machine (gray dashed line) increases, but remains smaller than the negative-sequence current of the induction generator. The direct current component of the synchronous generator (black dashed line) increases at dip initiation and shows a slow decay. The behavior of the direct and inverse current component of the converter-connected DG (full black and gray lines) is similar, but the increase is much smaller as compared to the other two generators.
Asynchronous and synchronous generators do not reduce the zero-sequence voltage component, since the neutral conductor is not connected. The converter-connected DG were represented by a number of small-scaled single-phase converters connected between a line and the neutral conductor in this simulation. They can exchange zero-sequence current components with the grid and are able to mitigate zero-sequence voltage components. The voltage dips resulting in zero-sequence current components are types B and E. The zero-sequence component of the voltage at the equipment terminals is slightly reduced, thanks to the operation of the converter-connected DG units (Table I). For threephase converter-based DG units, the neutral connector will most likely not be connected. Therefore mitigation of the zero-sequence component of the voltage is not possible.
VI. C ONCLUSION
In this paper, the influence of three different types of DG on the retained voltage during voltage dips in low voltage distribution networks are analyzed. The behavior of converter-based
DG, synchronous generators, and asynchronous generators during voltage dips was verified. In opposition to the reported effects of synchronous and asynchronous generators on voltage dips in high to medium voltage networks, their influence on voltage dips in low voltage networks was rather minimal. Converter-based DG was found to have a similar effect on voltage dips in low voltage networks, in opposition to high-voltage networks. A low voltage distribution feeder has been simulated for seven different types of voltage dips with the three types of
DG connected to the distribution feeder. The voltage dips as experienced by the load connected to the equipment terminals were mitigated most by converter-connected DG. However, the improvements are small as compared to the effects of DG on voltage dips in high voltage networks.
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[14] S. B. Kjaer, J. K. Pedersen, and F. Blaabjerg, “A review of single-phase grid-connected inverters for photovoltaic modules,” IEEE Trans. Ind.
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[15] W. R. Ryckaert, K. De Gussemé, D. M. Van de Sype, L. Vandevelde, and J. A. Melkebeek, “Damping potential of single-phase bidirectional rectifiers with resistive harmonic behaviour,” Proc. Inst. Elect. Eng.,
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[16] M. H. J. Bollen and I. Y. H. Gu , Signal Processing of Power Quality
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[17] W. Freitas, J. C. M. Vieira, A. Morelato, L. C. P. da Silva, V. F.
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[18] H. Cheng-Ting and F. Chun-Jen, “Dispersed generation systems impact on the voltage sags in distribution systems,” presented at the Int. Conf.
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[19] Considerations on Reference Impedances for Use in Determining the
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Bert Renders (S’06) was born in Ghent, Belgium, in 1981. He received the M.Sc. degree in electromechanical engineering from Ghent University,
Ghent, in 2004, where he is currently pursuing the
Ph.D. degree.
Currently, he is with the Electrical Energy Laboratory (EELAB) of Ghent University. His research interests include digital control of converter-connected distributed generation units and their contribution to power quality.
Authorized licensed use limited to: Belgium Hogeschools Consortium. Downloaded on March 20, 2009 at 11:13 from IEEE Xplore. Restrictions apply.

1588 IEEE TRANSACTIONS ON POWER DELIVERY, VOL. 23, NO. 3, JULY 2008
Koen De Gussemé (M’03) was born in Aalst, Belgium, in 1979. He received the M.Sc. and Ph.D. degrees in electromechanical engineering from Ghent
University, Ghent, Belgium, in 2001 and 2006, respectively.
Currently, he is a Researcher in the Department of
Electrical Energy, Systems and Automation of Ghent
University. His research topics are digital control of switching converters, power factor correction, and grid-connected inverters for distributed generation.
Lieven Vandevelde (M’05–SM’07) was born in
Eeklo, Belgium, in 1968. He received the Ph.D.
degree from the Electrical Energy Laboratory
(EELAB) of Ghent University, Ghent, Belgium, in
1997.
He graduated in electrical and mechanical engineering at Ghent University in 1992. Currently, he is Professor in electrical power engineering, where he has been since 2004. His research and teaching activities are in the field of electric power systems, electrical machines, and (computational) electromagnetics.
Wouter R. Ryckaert (M’02) was born in Ghent, Belgium, in 1976. He received the industrial engineer degree in electrical engineering from the Technical
University KaHo Sint-Lieven, Ghent, in 1998 and the
M.Sc. and Ph.D. degrees in electrical and mechanical engineering from Ghent University in 2001 and 2006, respectively.
Currently, he is with the Department of Industrial
Sciences, Laboratorium voor Lichttechnologie,
Technical University KaHo Sint-Lieven. His research interests include power quality, electric power systems, and grid-connected inverters for distributed generation.
Kurt Stockman (M’02) was born in Kortrijk,
Belgium, on September 24, 1972. He received the industrial engineer degree in electrical engineering from Provinciale Industriële Hogeschool, Kortrijk, Belgium, in 1994 and the Ph.D. degree from
Katholieke Universiteit Leuven, Leuven, Belgium, in 2003.
Currently, he is with the Department of Electrical
Engineering of the Hogeschool West-Vlaanderen,
Kortrijk, Belgium. His research and teaching activities are in the field of electromechanical drives and
Math H. J. Bollen (M’93–SM’96–F’04) received the
M.Sc. and Ph.D. degrees from the Eindhoven University of Technology, Eindhoven, The Netherlands, in
1985 and 1989, respectively.
Currently, he is Manager of EMC and Power
Quality at STRI AB, Ludvika, Sweden, and Guest
Professor with EMC-on-Site, Luleå University of
Technology, Skellefteå, Sweden. Before joining
STRI in 2003, he was a Postdoctor with the Eindhoven University of Technology, a Lecturer with the University of Manchester Institute of Science and Technology (UMIST), Manchester, U.K., and Professor of Electric Power
Systems at Chalmers University of Technology, Gothenburg, Sweden. His research interests cover a wide range of subjects in power systems, with an emphasis on power quality, reliability, and related issues. He has written many basic papers on voltage-dip analysis and a textbook on power quality.
power quality.
Authorized licensed use limited to: Belgium Hogeschools Consortium. Downloaded on March 20, 2009 at 11:13 from IEEE Xplore. Restrictions apply.