DISTRIBUTED GENERATION AND RECLOSING COORDINATION
Lauri Kumpulainen, VTT Technical Research Centre of Finland
lauri.kumpulainen@vtt.fi
Kimmo Kauhaniemi, VTT Technical Research Centre of Finland & University of Vaasa
kimmo.kauhaniemi@uwasa.fi
ABSTRACT
Distribution networks have traditionally been designed for unidirectional power flow. Large
scale implementation of distributed generation (DG) means that this fundamental assumption
is not true any more. This causes several challenges to network design and operation. One of
the most critical affected areas is system protection. The impact of DG on protection has been
examined in several research papers during the last years. The most challenging issue seems
to be anti-islanding protection, especially when automatic reclosing is applied.
In this paper, the effect of DG on automatic reclosing is studied. After a short literature
review, the method and results of simulation studies are presented. The simulations verify the
existence of the problems. Protection requirements and possible solutions are discussed.
Because of speed and reliability requirements, telecommunication based protection seems to
be the most suitable solution, when the share of DG becomes significant.
IMPORTANCE OF AUTOMATIC RECLOSING
In medium voltage overhead networks all over the world automatic reclosing is widely used
and a very effective method of fault clearing. According to [1], 70-95% of the faults are
temporary. Figure 1 illustrates the importance of automatic reclosing according to a Finnish
study [2].
Figure 1. Share of different faults and fault clearing by automatic reclosing in Finnish
overhead networks [2].
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IMPACT OF DISTRIBUTED GENERATION ON AUTOMATIC RECLOSING
Challenges to protection caused by DG
Connection of DG into distribution networks convert simple systems into complicated
networks. Previously radially fed systems will have multiple sources which change the flow
of fault currents. Traditional protection schemes may become ineffective. Previous studies
have shown e.g. the following challenges to network protection [3]:
• False tripping of feeders (sympathetic tripping)
• Nuisance tripping of production units
• Blinding of protection
• Increased or decreased fault levels
• Unwanted islanding
• Prevention of automatic reclosing
• Unsynchronized reclosing
Prevention of automatic reclosing
Islanding and reclosing problems are closely linked together. DG may continue operation
during the autoreclose open time, sustaining voltage and feeding fault current. Thus it may
prevent fault arc extinction. This leads to unsuccessful reclosure, and the fault that would
have been temporary becomes permanent. By preventing successful reclosing DG may
deteriorate the reliability of networks and increase the number of customer minutes lost.
Unsuccessful reclosing attempt also increases stresses to network components, because the
reclosing circuit breaker will be closed against a fault.
If a generator is connected to the low voltage side of a delta-wye connected distribution
transformer, the generator will not feed earth-fault current to an earth fault in the MV
network, because the transformer prevents the flow of zero-sequence current. However, the
generator can sustain voltage on the MV network, and thus sustain the fault arc. Because the
detection of MV earth fault on the LV side is difficult, this can be a problematic issue, if the
DG units are connected far from the MV/LV transformer.
Distributed generation units should be disconnected clearly before the reclosure, so that there
will be enough time for arc extinction and arc path dissipation. Otherwise the arc will reignite immediately after the reclosing.
Out-of-phase reclosing and its possible consequences
Even more severe problem than prevention of successful reclosing may occur, when DG units
are not tripped during the autoreclose open time. The generators can accelerate or decelerate
so that the reclosure occurs at the moment when the voltages in the islanded part of the
network and in the main grid are in phase opposition. This can have severe consequences.
Overvoltages, overcurrents, and large mechanical torques are possible. These can cause
serious damage to rotating generators and motors. Also other equipment, connected to the
network, is vulnerable to extra stresses. According to [4], there is little documentation of
actual damage to turbine-generators resulting from autoreclosing, but the effects of these
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stresses are cumulative. If generation is connected to the system by means of inverter, the risk
of damage to the DG unit is lower. References [5], [6] emphasize the risks to rotating
machines and [7] reports that circuit breakers can be damaged in non-synchronised reclosing.
Exceptionally high inrush or starting current in transformers or motors are possible, and they
can lead to unnecessary tripping of protection or cause mechanical damage in motors [8].
In reference [9] the avoiding of out-of-step reclosing is regarded as the most difficult of the
problems caused by inadvertent islanding, because the time to detect the island is very short.
SIMULATION STUDIES
System modelling for simulation studies
Dynamic modelling of DG and the power system is a key issue in simulation studies of power
system behaviour in fault situations. In this study electromagnetic transient simulation
software PSCAD™ was used for modelling of the power system, DG units and protection
relays. Most of the models applied in these simulations were from a custom made component
library that has been developed in research projects during a period of several years.
The network model was based on Finnish rural overhead network. Similar network structures
are common also in other parts of Europe. The simplified medium voltage network model
consisted of an equivalent circuit representing the feeding HV network, primary transformer
and two MV feeders. One of the feeders was modelled with more details and the other feeder
was used only for studying faults located in the adjacent feeder. In addition to these there was
an equivalent circuit representing all the other feeders connected to the primary substation. A
scheme of the network model is presented in Figure 2.
Figure 2. Scheme of the network model applied in the simulations.
The network model was equipped with basic overcurrent and earth-fault relays, and there was
an option for high-speed 3-pole reclosing. For earth-fault protection directional earth-fault
relays were applied since the earthing practices of the simulated cases included earth-isolated
and resonant earthed systems.
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The generator types applied in the simulations were asynchronous generator and synchronous
generator. Only rotating generator models were applied, since the impact of inverter based
units on fault current is much lower than the impact of rotating generators, and it will be
studied later. The asynchronous generator (wind power plant, 1.65 MW) was applied in a
directly connected fixed speed wind generator. The diesel power plant (7.94 MVA) model
was based on a synchronous generator and the model was developed together with a power
plant manufacturer. In the simulations one or several generators could be connected to any
point in feeder 1 of the network model.
The DG units were also equipped with protection devices. Typically DG unit models have
both under-/overvoltage and under-/overfrequency relays. So far specific loss-of-mains relay
models have not been included in the models.
Fault arc model
A third party developed prototype arc model was applied in some of the simulations. The
model has been developed according to theory presented in [10]. The arc model consists of
two separate models, primary arc and secondary arc. Primary arc model is applied before the
tripping of the circuit breaker and secondary arc model after breaker tripping. In HV network
1-pole reclosing the mutual coupling of phases sustains the voltage of the faulty phase and the
fault arc. In these MV network simulations the reclosing was 3-pole, and DG units sustained
the secondary arc.
The fault arc model was verified to some extent by comparing simulated arc voltage with
measurements. Figures 3a, 3b, and 3c present the comparison. In the figures one can note the
secondary arc voltage waveform and the arc extinction, when the waveform becomes
sinusoidal.
Figure 3a. Simulated arc voltage.
Figure 3b. Measured arc voltage, Finnish 20 kV network [11].
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Figure 3c. Measured arc voltage waveform in 20 kV network, recorded in a Finnish primary
substation (by courtesy of Vaasan Sähkö Oy and ABB Substation Automation).
Results of the simulations
Simulated cases were network fault cases, and the main objective was to analyse the impact of
DG on the protection of the system, especially on high-speed reclosing. Both symmetrical and
unsymmetrical faults were simulated.
Figure 4 presents the behaviour of phase voltages in a short-circuit fault case with successful
reclosing when there are no DG units running. The fault occurs at t = 0.5 s, the circuit-breaker
of the feeder trips at t = 0.9 s and recloses successfully at t = 1.2 s.
Figure 4. Successful automatic reclosing (high-speed reclosing).
The ability of DG units to sustain fault current after tripping of the feeder breaker was verified
by the simulations. Figure 5 presents simulation results of a 2-phase short-circuit fault when a
diesel power plant is running. The power plant keeps operating 0.8 seconds after the feeder
breaker has tripped. If there had been a reclose attempt after a typical 0.3 s autoreclose open
time, the reclosing would have failed.
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Figure 5. Power of the generator and the fault current in a 2-phase short-circuit fault case.
Figure 6 presents simulation results when the fault arc model has been applied. The fault case
is single phase to earth, and the wind power connected to the feeder is able to sustain
operation during the autoreclose open time. Figure 6 illustrates the secondary arc voltage. In
the case the feeder trips at t = 2.0 s and recloses unsuccessfully at t = 2.3 s.
Arc voltage
20
Voltage (kV)
10
0
-10
-20
-30
1,9
2,0
2,1
2,2
2,3
2,4
Time (s)
Electrotek Concepts®
TOP, The Output Processor®
Figure 6. Simulated secondary arc voltage during the autoreclose open time, single-phase-to
earth case.
In arc faults the secondary arc is sustained by distributed generation. This could clearly be
seen when comparing simulation results of cases with and without DG units. When DG units
were not present, there was virtually no secondary arc at all.
The simulation of Figure 7 illustrates the ability of wind power plants (3 asynchronous
generators) to sustain operation during a single phase to earth fault. When a fault occurs at t =
1.5 s in a network with isolated neutral, the voltage of the faulty phase decreases, but the
voltages of the healthy phases increase. After the tripping of the feeder breaker at t = 1.9 s the
voltage sustained by the wind power plants gradually decreases. An unsuccessful reclose
attempt can be seen at t = 2.2 s.
Recorded data from a real network verifies the simulated effect of wind power plants. Figure
8 illustrates the recorded phase voltages in the beginning of a feeder having wind power
plants connected in a fault situation.
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Figure 7. Simulated phase voltages in an earth fault, unsuccessful reclose attempt.
Figure 8. Voltage waveforms recorded in a Finnish primary substation (by courtesy of
Vaasan Sähkö Oy and ABB Substation Automation).
Figure 9 illustrates the development of the phase difference of the feeder and the grid during
the reclosing sequence of the above (Fig. 7) simulation. In this case the reclosing occurs
almost in phase opposition.
Figure 9. Phase difference between the feeder fed by wind power plants and the main grid
during an autoreclosing sequence.
As stated before, out-of-phase reclosing can lead to significant current, voltage and torque
transients. Figure 10 present the behavior of the current of the generator during the above
described reclosing.
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Current of the generator
10
I (kA)
5
0
-5
1,6
1,8
2,0
2,2
2,4
2,6
Time (s)
Electrotek Concepts®
TOP, The Output Processor®
Figure 10. Current transient of the generator in reclosing.
Simulations with the diesel power model verify the risks linked to out-of-phase reclosing.
Although the phase difference at the moment of the reclosing of Figure 11 is only 35 degrees,
there are significant active and reactive power transients.
Power transient at reclosing, diesel power plant
P
20
Q
P, Q (MW, MVAr)
15
10
fault occurs
feeder trips
5
0
-5
-10
10,0
reclosure
10,5
11,0
11,5
Time (s)
Electrotek Concepts®
TOP, The Output Processor®
Figure 11. Active and reactive power transients of a diesel power plant at an out-of-phase
reclosing.
PROTECTION NEEDED TO SECURE AUTOMATIC RECLOSING AND TO
PREVENT OUT-OF-PHASE RECLOSING
It is obvious that automatic reclosing is problematic when there is distributed generation
connected to the network. As [12] states, it is unrealistic to think that utilities would abandon
reclosing for the sake of dispersed generation safety. Instead of that, automatic reclosing has
often been considered in interconnection rules, as a special case of anti-islanding protection.
Normally it is required that DG units should be disconnected before the reclosing of the
circuit breaker. This is perhaps not adequate, because in order to have enough time for fault
arc extinction and arc path de-ionization, there should be a clear dead time (no voltage time
before the reclosure). Because typical open time of high-speed autoreclosing is in the range of
0.3…0.5 seconds, very fast protection is needed.
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Increasing autoreclose open time
Reference [4] states that in most cases it will be necessary to delay autoreclosing, to allow
customer generator disconnection before reclosure. Also [13] recommends that instantaneous
reclose should not be used on feeder sections that contain DG. Instead a reclose interval of 1 s
is preferred. This would certainly make anti-islanding protection easier, but it would lead to
reduced power quality for other customers, which is hardly acceptable [14]. According to
[15], the trend is towards shorter reclosure dead time.
Voltage sensing or sync-check relays for the circuit breaker
Additional security against out-of-phase reclosure can be provided by dead-line voltage
sensing or synchronizing check [4]. However, voltage and synchronisation checking can be
considered as backup for anti-islanding protection, not as a primary solution to reclosing
problems caused by DG. Otherwise their implementation will lead to deterioration of supply
quality, because they could prevent reclosing, and faults that would have been temporary
would become permanent.
Anti-islanding protection
In several national interconnection recommendations it is required that distributed generation
must not feed into circuits that have been de-energized from the main grid and that the DG
units have to be disconnected before the reclosing. In some countries, a specific loss-ofmains protection is required.
Several methods for anti-islanding protection have been proposed. The methods can be
divided into three categories: passive methods, active methods, and telecommunications based
methods.
Although some of the passive methods, such as ROCOF (rate of change of frequency) or
Vector Shift are widely applied, they have significant drawbacks. According to [16], both
theoretical analysis and physical experimentation have demonstrated that any single passive
method has a non-detection zone. Furthermore, these methods often cause nuisance tripping
of generating units. As the share of DG increases, load matching situations become more
probable, and the effectiveness of passive anti-islanding methods can be argued. E.g.
Yorkshire Electricity does not permit ROCOF or Vector Shift methods for generators larger
than 1 MW, because of concern over both non-operation and spurious common mode
operation of these relays [17].
Active methods have often been designed for inverter based small production units. Their
operation is based on destabilization of the island. They have been suspected for adverse
impacts on grid dynamics and ineffectiveness, if there are multiple sources in the network
[16]. Active methods hardly are applicable for large DG units.
According to [18], the only way to guarantee anti-islanding protection is intertripping from
the circuit breaker at the primary substation. Also [19] regards transfer trip as the most
effective method for anti-islanding. In networks with line reclosers, direct transfer trip would
probably require communications not only from the substation breaker but also from all the
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reclosers upstream from the distributed resources [1]. In addition to non-operation, all antiislanding techniques except intertripping can be susceptible to common mode tripping.
Common mode tripping could lead to serious disturbance and stability problems. [17]
Another argument for telecommunication based anti-islanding protection is the speed
requirement. If high speed reclosing is applied, and some time should be reserved for arc
extinction, the protection should disconnect DG units very rapidly. The speed requirement
may be difficult to achieve using passive or active protection schemes. Reference [4] admits
that to maintain service reliability to other customers, a communications-aided protection
package could be needed.
If the configuration of the network is permanent, fixed point-to-point or point-to-multipoint
communication channels can be used. If the structure of the network is open loop or linked,
trip signals to DG units should be sent according to current network configuration, because
the island zone can be changed. Power-line carrier based communication has potential to
overcome this issue, because the signal is always communicated to the correct generators
without any need for re-configurations [17]. Interesting concepts based on distribution line
carrier or ripple signal have been sketched in references [20] and [21].
CONCLUSION
Automatic reclosing is an essential tool for keeping quality of service acceptable. It is a
prevalent practice in overhead distribution networks throughout the world. Distributed
generation can both prevent successful operation of autoreclosing by sustaining fault during
the autoreclose open time, and even worse, cause out-of-phase reclosing. These impacts have
been verified by simulations.
To prevent the possible problems caused by DG, fast and reliable anti-islanding protection is
needed. Although several protection algorithms for this purpose have been proposed, it seems
that the only reliable methods are based on telecommunications. There are several possible
alternatives for communication channels. If there are several units connected to the feeder and
if the configuration of the network can be changed, distribution line carrier or ripple signal
based methods could provide interesting solutions.
References
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