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IEEE TRANSACTIONS ON POWER DELIVERY, VOL. 21, NO. 3, JULY 2006
Performance of Frequency Relays for
Distributed Generation Protection
Jose C. M. Vieira, Student Member, IEEE, Walmir Freitas, Member, IEEE, Wilsun Xu, Fellow, IEEE, and
Andre Morelato, Member, IEEE
Abstract—This paper investigates the efficiency of under/over
frequency relays for protection of distributed synchronous generators considering islanding detection and frequency-tripping requirements. Comparison between frequency and vector surge relays, which are islanding detection-dedicated devices, shows that
the former can be as effective as the latter. This feature supports
the idea that frequency relays can replace vector surge relays for islanding detection purpose. In this case, frequency relays must also
meet the generator manufacturer recommendations and the utility
frequency-tripping requirements. In order to investigate the relay
capability to meet both necessities, it is proposed the concept of application region, which defines a region in the detection time versus
active power imbalance space where frequency-based relays can be
adjusted to satisfy the anti-islanding and frequency-tripping requirements simultaneously. The paper also presents a set of formulas to determine directly the application region.
Index Terms—Distributed generation, dynamic simulation,
frequency relay, islanding detection, synchronous generator.
I. INTRODUCTION
P
ROTECTION systems of distributed synchronous generators must be able to detect islanding situations and meet the
utility frequency-tripping requirements. An islanding situation
occurs when part of a distribution system is disconnected from
the utility system, but it remains energized due to one or more
distributed generators connected to the isolated subsystem. This
occurrence, also known as loss of mains, may lead to safety risks
to the utility personnel, deteriorate the quality of supply in the
island and cause damage to the distributed generator (DG) and
loads. In an attempt to minimize such risks, the current practice in the industry is to disconnect all distributed generators
immediately after an islanding occurrence [1]–[3]. Typically,
the islanding situation should be detected within 200 to 400 ms,
however, this requirement has been relaxed by some utilities and
detection times up to 1 s are allowed. To achieve such a goal,
each distributed generator must be equipped with an islanding
detection device. Vector surge (or shift) relays (VSR) are developed for this purpose [4], [5]. These relays have gained widespread acceptance of the industry.
Manuscript received January 21, 2005; revised April 28, 2005. This work
was supported in part by FAPESP, in part by CNPq, and by PRPG/UNICAMP,
Brazil. Paper no. TPWRD-00039-2005.
J. C. M Vieira, W. Freitas, and A. Morelato are with the Department of Electrical Energy Systems, State University of Campinas, Campinas 13081-970,
Brazil (e-mail: jcarlos@dsee.fee.unicamp.br; walmir@ieee.org; morelato@
dsee.fee.unicamp.br).
W. Xu is with the Department of Electrical and Computer Engineering, University of Alberta, Edmonton AB T6G 2V4, Canada (e-mail: wxu@ee.ualberta.
ca).
Digital Object Identifier 10.1109/TPWRD.2005.858751
As a standard practice, all distributed synchronous generators are also equipped with under/over frequency relays, whose
settings are established according to the generator manufacturer
recommendations and to the utility frequency-tripping requirements (or interconnection) guidelines [1]. Since both the vector
surge and the frequency relays operate on the basis of system
frequency deviation, one would wonder if the frequency relay
can replace the vector surge relay for anti-islanding detection
application. If this is the case, installation of a dedicated islanding detection relay, such as the VSR, will become unnecessary. The savings can be quite attractive for small-distributed
generators and the protection system would be much simpler.
Another significant issue raising from using frequency-based
relays for anti-islanding protection is the conflicting requirement on the relay performance. The IEEE distributed resources
interconnection guide recommends that a DG must not be disconnected due to small frequency variations [1]. If the relay is
set to meet this requirement, it may not detect islanding conditions within the required time. On the other hand, if the relay is
set sensitive for anti-islanding protection, it may also trip the DG
due to small frequency variations. Thus, it is important to understand if there is a region where the relay can satisfy both requirements and, if such a region exists, what are its characteristics.
The main objective of this paper is to present our findings on
the above two questions. Our results show that frequency relays
have essentially the same performance of vector surge relays
for islanding detection. For the second question, we found that
there is a region where the frequency relay can satisfy the both
requirements mentioned previously. A method to determine this
region is proposed.
This paper is organized as follows. Section II explains
the approach employed in this work to analyze the islanding
detection capability of frequency-based relays. Section III
describes the network component models used in this work.
Section IV presents a comparative study between the performance of frequency relays (FR) and vector surge relays (VSRs)
for anti-islanding protection. Section V proposes the concept
of application region where the frequency relay can be used
for anti-islanding protection while maintaining immunity to
small frequency variation. The conclusions are presented in
Section VI. In Appendix, it is proposed a set of formulas to
determine the application region without simulations.
II. PERFORMANCE CURVES
The usage of the performance curves, i.e. the detection time
versus active power imbalance curves, in order to characterize
frequency-based relays was proposed in [6], where detailed
0885-8977/$20.00 © 2006 IEEE
VIEIRA et al.: PERFORMANCE OF FREQUENCY RELAYS
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Fig. 2.
Single-line diagram of the system.
Fig. 1. Typical performance curve of frequency-based relays.
information can be found about this approach. However, to
facilitate the paper reading, the determination and analysis of
these curves are briefly explained in this section. The islanding
detection capability of frequency-based anti-islanding relays
is strongly dependent on the active power imbalance existent
in the islanded system, i.e. the mismatch between load and
generation. When the mismatch of active power decreases, the
capability to quickly detect islanding of these devices diminishes accordingly [6]. In the extreme cases, where the load and
generation in the islanded system are very close, the devices
may fail to detect an islanding situation [6]. Thus, an approach
to evaluate the performance of frequency-based anti-islanding
relays is to understand the relationship between the detection
time and active power imbalance. This relationship can be represented through a detection time versus active power imbalance curve as shown in Fig. 1, which is obtained for a specific
relay setting.
In Fig. 1, the -axis is the active power imbalance level of the
islanded system referred to the rated MVA of the generator. The
y-axis is the time needed by the relay to operate. This curve can
be obtained by repeated dynamic simulations of islanding occurrences, in which the load-generation profile in the islanded
system is changed for each simulation. Thus, for each active
power imbalance, the detection time is determined by dynamic
simulation and then the performance curve is plotted. If it is required to detect the islanding situation within 400 ms after its
occurrence, one can draw a 400-ms horizontal line. In this case,
the intersection of this line with the relay curve gives 21.7% of
active power imbalance level. If the islanded system has an active power imbalance greater than 21.7%, it will take less than
400 ms to detect the islanding condition. Therefore, the relay
can be used with confidence. On the other hand, the relay will
take longer than 400 ms to operate if the active power imbalance level is less than 21.7%. Consequently, the relay or the setting employed is not suitable for this case. Such a threshold is
called the critical active power imbalance level or simply critical power imbalance [6].
Fig. 3. Frequency relay computational model.
III. NETWORK COMPONENT MODELS
Fig. 2 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 Thévenin equivalent (Sub), which feeds a 33 kV distribution
, transformer. In this system,
system through a 132/33 kV,
there is one 30 MW synchronous generator (SG) connected at
bus 5, which is connected to the network through one 33/0.69
transformer. Such generator is equipped with an aukV,
tomatic voltage regulator (AVR).
In this study, all network components were represented by
three-phase models. Distribution feeders were modeled as series
impedances and transformers were modeled using the circuit. Synchronous generators were represented by a sixth-order
three-phase model in the rotor reference frame [7]. The generator was considered equipped with an automatic voltage regulator represented by the IEEE—Type 1 model. The simulation
duration is short (1 s), in addition, usually, distributed generators do not participate in the frequency regulation of the system
and, therefore, they operate at constant active power mode [5].
Thus, the mechanical power was considered constant. The loads
were modeled as constant impedance, because this type of load
leads to the most conservative (pessimistic) islanding detection
performance of frequency-based relays [6].
Frequency relays measure the cycle duration of the terminal
voltage by using some voltage zero crossing detection technique
and signal processing method. The frequency relay model implemented in this work is presented in Fig. 3. The system frequency is determined from the generator electrical speed .
If this signal is larger (or smaller) than the over frequency (under
frequency) setting of the relay and the magnitude of the ter,
minal voltage is larger than the minimum voltage setting
then the frequency relay sends a trip signal to the generator
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IEEE TRANSACTIONS ON POWER DELIVERY, VOL. 21, NO. 3, JULY 2006
circuit breaker. For simplicity, it was considered that the deviations of the relay settings for under/over frequency are the
occurs, the
same. Therefore, if a variation of frequency
frequency relay becomes active. Frequency relays can be operated with a time delay; in this case, the tripping conditions
(frequency variation) must persist during a pre-determined time
to trigger the relay. Typically, frequency relays can be adjusted
using multi-stages, therefore, instantaneous and time-delay settings are employed simultaneously. Usually, frequency relays
can be blocked if the terminal voltage drops below an adjustable
. This is to avoid, for example, the actuation of the
level
relay during generator start-up.
Vector surge relays measure the duration time of an electrical cycle and start a new measurement at each zero rising
crossing of the terminal voltage and the current cycle duration
(measured waveform) is compared with the last one (reference
cycle). Variations of the cycle duration results in a proportional
variation of the terminal voltage angle, which is the input parameter of vector surge relays. If the variation of the terminal
voltage angle exceeds a pre-determined threshold, a trip signal
is immediately sent to the generator circuit breaker. Usually,
vector surge relays allow this angle threshold to be adjusted
in the range from 2 to 20 degrees. A detailed description of
vector surge relays is presented in [5]. VSRs were simulated as
follows. The generator terminal voltage angle is determined
in every integration step. A reference terminal voltage angle
is computed and updated at the beginning of each electrical cycle. The absolute variation between these two angles,
, is calculated in every integration step and compared with the angle threshold . Additionally, the rms value
of the terminal voltage is also determined in every integration
is larger than the angle threshold
step. If the angle variation
and the magnitude of the terminal voltage is larger than the
, the VSR immediately sends
adjusted minimum voltage
a trip signal to the circuit breaker. More details about the VSR
computational model can be found in [6].
The main difference concerning the operating principles of
frequency and vector surge relays is the reference value used to
trigger the relay. While the frequency relay uses a fixed reference, the rated system frequency (60 Hz in this work), the reference value used by a vector surge relay is updated cycle by
cycle, indeed, the last cycle duration or some average value calculated using a few cycles [5], [6].
TABLE I
CORRESPONDENCE BETWEEN FREQUENCY AND VECTOR SURGE
RELAYS SETTINGS IN A 60 HZ SYSTEM
IV. COMPARATIVE ANALYSIS BETWEEN FREQUENCY RELAYS
AND VECTOR SURGE RELAYS FOR ISLANDING DETECTION
In this section, a comparison between the islanding detection
capability of frequency and vector surge relays is carried out by
using the performance curves. Such curves are obtained through
repeated dynamic simulations. The islanding situation is simulated by opening the circuit breaker CB installed at bus 2 at
s (Fig. 2), which remains open until the end of the simulation at
s. Then, if the relay installed at bus 5 does
not become active within 1.0 s, it is considered that this device
fails to detect the islanding. The active power imbalance of the
islanded system is gradually varied from 0 to 1 pu, referred to
the MVA rating of the generator, by changing the pre-islanding
Fig. 4.
Performance curves of VSR and frequency relays.
TABLE II
CRITICAL POWER IMBALANCE: COMPARATIVE ANALYSIS BETWEEN FR
AND VSR ANTI-ISLANDING PERFORMANCES
generation-load profile. For each case of active power imbalance, dynamic simulation is conducted to determine the relay
detection time and then the curves are plotted [6].
In a 60 Hz system, 1 Hz corresponds to 6 electrical degrees.
Therefore, the relationships presented in Table I are adopted for
comparison purpose.
The performance curves for three different vector surge and
frequency relays settings are presented in Fig. 4. Results show
that the performances of both relays are quite similar. The
critical power imbalances for typical relays settings considering
that the required detection time is 300, 500 or 700 ms are
presented in Table II. In this table, the values are in percentage
of the generator MVA rating; the frequency relay is referred
as FR and the vector surge relay as VSR. It can be noted that
both relays lead to very similar critical power imbalances. The
significance of this finding is the following: the vector surge
relay does not offer additional advantages than the frequency
VIEIRA et al.: PERFORMANCE OF FREQUENCY RELAYS
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TABLE III
INTERCONNECTION SYSTEM RESPONSE TO ABNORMAL FREQUENCIES
relay for anti-islanding protection. As a result, there is no
need to install a dedicated VSR for anti-islanding application
because a frequency relay can be as effective as the vector
surge relay.
V. CONSTRAINTS IMPOSED BY THE FREQUENCY-TRIPPING
REQUIREMENTS
Technical guides for DG interconnection recommend that the
generators should not be disconnected instantaneously due to
small frequency variations [1]. Table III shows the frequencytripping requirements recommended in [1] for distributed generators during abnormal frequencies. As a result, one cannot set
a frequency relay very sensitive for anti-islanding protection.
A well-designed DG protection scheme must satisfy both the
anti-islanding and frequency-tripping requirements simultaneously. This section investigates if this objective can be met by
frequency relays.
Fig. 5. Performance curves of frequency relays for delayed and instantaneous
operation.
TABLE IV
CRITICAL POWER IMBALANCES FOR FREQUENCY RELAYS
A. Behavior of Frequency Relays
According to the recommendations stated in Table III, typical
time delays vary from 160 ms to 300 s. This delay includes the
circuit breaker opening time. Thus, time-delay settings as low
as 100 ms can be used. In this section, a time delay equal to
300 ms was applied to the lower settings of the frequency relay
(0.5 to 1.5 Hz). On the other hand, higher settings were operated instantaneously, as is usual. The required detection times
analyzed were 300, 500 and 700 ms. Dynamical simulations
using the test system of Fig. 2 were carried out to determine the
performance curves of frequency relays considering time-delay
and instantaneous settings. The results are summarized in Fig. 5
and Table IV, where the values of the critical power imbalances
are in percentage of the distributed generator MVA rating. The
second column of Table IV shows that time-delay settings are
not able to detect an islanding condition if the detection time required is 300 ms. Frequency relays with instantaneous settings
can detect the islanding in all the cases, but the active power imbalance necessary to operate the relay can be higher than 50%
of the generator rated power. When the required detection time
is increased, the critical power imbalance necessary to a successful islanding detection decreases. In addition, the third and
fourth columns indicate that it is possible to coordinate the instantaneous and time-delay settings of frequency relays in such
a way that the frequency-tripping requirements are not violated
and the critical active power imbalance is minimized. An approach to graphically determine these settings is proposed in the
next section.
B. Application Region of Frequency Relays
The results shown in Fig. 5 and Table IV indicate that there
is a region where the frequency relay can satisfy both antiislanding and frequency-tripping requirements. Moreover, it is
also shown that a frequency relay can reach such objective if
its instantaneous and time-delay settings are properly chosen.
This section proposes a graphical methodology that helps protection engineers to evaluate the frequency relay settings acceptable for both purposes. The methodology defines an acceptable operating region for frequency relays in the detection time
versus active power imbalance space. Such region is called application region of frequency relays. Inside this region, both criteria are satisfied. Fig. 6 shows the application region for a frequency relay considering a required detection time of 500 ms
and the under frequency requirements of Table III. The application region was obtained by using the performance curves of the
frequency relay. Such curves were obtained through dynamical
simulation, using the test system of Fig. 2. It can be observed in
Fig. 6 that the application region is delimited by the following
curves.
• Performance curve for the 0.2 Hz setting (59.8 Hz): this
curve represents the lower limit of the region. Between
59.8 Hz and 60 Hz the relay must not operate—this is the
frequency variation immunity requirement. Thus, curves
below the 0.2 Hz curve refer to settings smaller than
0.2 Hz, which are not allowed. This curve is the frequency
variation immunity curve.
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Fig. 6. Application region of a frequency relay, considering underfrequency
settings (deficit of active power).
Fig. 7. Application region of a frequency relay: a practical application
considering the underfrequency setting of 59 Hz and different time-delays.
• Performance curve for 3 Hz (57 Hz): it represents the
upper limit of the region. This curve is related to the instantaneous requirements for the system frequency. Referring
to Table III, it refers to the 57 Hz setting. Curves above the
upper limit curve indicate settings that are not allowed.
• Anti-islanding requirement: it is a horizontal line that represents the time required to detect the islanding condition.
Usually, frequency relays are equipped with two or more
groups of settings, which allow the relay to be configured
with time-delay and instantaneous settings simultaneously.
In the case analyzed in this work, it was assumed that the
instantaneous under frequency setting is adjusted to 3 Hz (57
Hz), satisfying both the islanding and frequency requirements.
Fig. 7 shows this situation and the usefulness of the application
region concept. For a 57 Hz setting the critical power imbalance
is 38.15%. The big issue is how to adjust the time-delay stage
of the relay under frequency setting. Assume that the value of
59 Hz is chosen as the frequency setting for the time-delay
stage. The performance curve for such setting is presented in
Fig. 7 considering different time-delays: 100, 300 and 500 ms.
If the 59 Hz time-delay curve is above the application area, the
IEEE TRANSACTIONS ON POWER DELIVERY, VOL. 21, NO. 3, JULY 2006
Fig. 8. Application region of a frequency relay: optimum setting.
frequency-tripping requirements are satisfied but the islanding
detection capability of the frequency relay is limited by the
critical power imbalance of the 57 Hz-instantaneous curve. In
this case, this occurs if the time-delay is set equal to 500 ms.
On the other hand, if the time-delay stage is adjusted to operate
inside the application region, the frequency-tripping requirement is still satisfied and the islanding detection capability is
improved. For example, if the time-delay stage is set to 300
ms or 100 ms, the critical power imbalance is reduced from
38.15% to 33.82% and 21.76%, respectively.
Indeed, using the concept of application region, one can improve even more the islanding detection capability of frequency
relays by choosing a more suitable time-delay setting. Fig. 8
shows the application region and the performance curve of the
frequency relay with a 59.7 Hz, 100 ms time-delay setting. In
this case, the critical power imbalance is reduced to 12.74% and
the frequency-tripping requirements are not violated. This is the
optimum setting if the relay must meet both requirements simultaneously.
In the cases above analyzed, the frequency relay is triggered
due to the under frequency settings because there is deficit of active power in the islanded system. Similar analyzes and conclusions can be obtained for the case with excess of active power,
where the relay is triggered due to the over frequency settings.
Although these cases have been simulated, they are not shown
in this work due to space limitation.
VI. CONCLUSIONS
This paper presented an investigation of the performance of
standard under/over frequency relays for distributed generators
protection. The analyzes of the results lead to important conclusions and contributions to protection engineers, which are summarized as follows.
• Vector surge relays and frequency relays present very
similar performances for anti-islanding detection. Indeed,
vector surge relays can be considered a special case of
frequency relays. Thus, frequency relays can replace VSR
for islanding detection without adverse implications if
proper settings are chosen.
VIEIRA et al.: PERFORMANCE OF FREQUENCY RELAYS
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• The frequency-tripping requirement will limit the islanding detection capability of frequency-based relays.
In order to determine the relay settings that meet both
requirements the application region of frequency relay can
be used. This graphical approach is the main contribution
of this paper. It can be used to determine the time-delay
settings of frequency relays.
It is worth pointing that the application region can be extended to any other frequency-based relays, such as vector surge
and rate of change of frequency relays. In the next step, we will
investigate this possibility.
In the Appendix a set of formulas is developed that permits
one to obtain the application region of frequency relays directly.
This procedure decreases considerably the time spent during the
design of frequency-based protection system of distributed generators.
APPENDIX
FORMULAS TO DETERMINE THE APPLICATION
REGION OF FREQUENCY RELAYS
Fig. 9. Performance curves of frequency relays obtained by simulations and
analytical formula (constant power loads).
The system angular speed in the time can be represented by
; substituting it in (2), follows:
In this appendix, a set of formulas is introduced, which
permits to build the application region of frequency relays
directly. With such formulas, a protection engineer can decide
if frequency relays are suitable for his/her system and adjust the
instantaneous and time-delay settings readily, decreasing the
amount of simulations considerably. The development of the
formula is based on the reasoning described in [6], however,
the final formulas are quite different because the principle of
the vector surge and frequency relays are distinct. Firstly, an
analytical formula is developed considering constant power
loads. In the sequence, a correction factor is introduced to
extend the results to voltage-dependent loads.
A. Analytical Formula
Considering the system presented in Fig. 2, at steady state
the mechanical power
of the distributed generator is baland the electrical power
anced with the load electrical power
provided (or consumed) by the power grid. Therefore,
the distributed generator rotor speed and angle are constant.
If some disturbance occurs provoking an active power imbal, the system frequency starts to change because the
ance
power imbalance
causes transients in the distributed generator. The dynamic behavior of the synchronous generator can be
determined by using the machine swing equation. In the mathematical development below, the following assumptions are considered: (a) the load is represented by a constant power model;
(b) the generator is represented by the classical model. The
swing equation of the synchronous generator is given by
(1)
(3)
where
. Therefore
(4)
Equation (4) gives the relationship between frequency deviation (relay setting), detection time and active power imbalance.
Solving (4) for , we have
(5)
is the relay setting. Frequency relays can be adjusted
where
with time-delay settings. In this case, frequency variation must
persist during a pre-defined interval of time to activate the relay.
Thus, the relay time-delay setting must be introduced in (5) as
follows:
(6)
is the time-delay applied. With (6), one can obtain
where
the detection time versus power imbalance curves and, consequently, the application region. The validity of the mathematical development is confirmed by simulation, considering constant power loads in the system of Fig. 2. The relay performance
curves obtained by simulation and the formula are presented in
Fig. 9 for different instantaneous and time-delay settings. Very
good match can be observed between the two sets of the relay
performance curves.
B. Modified Empirical Formula
where is the generator inertia constant, is the synchronous
speed and the other variables have been defined previously. The
rotor speed can be solved from (1) as
(2)
The analytical formula developed in the previous subsection
considers that the power imbalance after the opening of the circuit breaker is constant. However, it occurs only if the loads have
characteristics of constant power. In addition, the islanding detection capability of frequency-based relay should be analyzed
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IEEE TRANSACTIONS ON POWER DELIVERY, VOL. 21, NO. 3, JULY 2006
Fig. 10. Performance curves of frequency relays obtained by simulations
and by the modified empirical formula (constant impedance loads—the most
conservative case).
taking into account the most conservative (pessimistic) situation, i.e. the situation where the critical active power imbalances
assumes the highest values. This occurs in the presence of constant impedance loads [6]. In this case, the active power imbalance may decrease after the islanding, becoming more difficult
to detect the islanding situation.
Based on extensive simulations carried out in different systems with different distributed generators, it has been observed
that the largest active power imbalance variation in the presence
of constant impedance loads is usually between 10% and 30%.
Such variation depends on the characteristic of the system and
generator as well as on the operating point. Thus, a 20% reduction factor can be roughly applied to active power imbalance in
(6). Furthermore, based on the results presented, it can be verified that the detection time increases almost exponentially when
the power imbalance decreases. Thus, the 20% reduction factor
should not be applied directly to different values of power imbalance. Adopting that the power imbalance correction factor
affects the power imbalance in an exponential way, the final
can be calculated as
power imbalance
(7)
where
is the initial power imbalance value at the instant
of the opening of the circuit breaker. This power imbalance rein (6) to determine the frequency relay performance.
places
Thus, the final modified empirical formula is given by
(8)
The accuracy of the modified empirical formula is shown in
Fig. 10, where the performance curves for instantaneous and
time-delay settings obtained by simulation and by the modified
empirical formula (8) are compared. Again very good match
can be observed between the two sets of the relay performance
curves.
C. Application Region
The above mathematical development can be used to determine the application region of frequency relay directly. The ap-
Fig. 11. Application region of frequency relays obtained by simulations and
analytical formula (constant impedance loads).
Fig. 12. Application region of a frequency relay: optimum setting by using
formula (8).
plication regions of the frequency relay obtained by simulation
and by formula (8) are compared in Fig. 11. Note that one region
is over the other. It can be observed that reasonable accuracy is
obtained by using the modified empirical formula.
The possibility of obtaining the application region of frequency relay and the performance curves using the formula
permits that protection engineers evaluate the efficiency of
frequency-based protection systems of distributed generators
directly. This approach can also be used to determine the
best instantaneous and time-delay settings of frequency relays
regarding islanding detection and frequency-tripping requirements simultaneously. This procedure can save time during
project stage.
For example, the optimum time-delay setting can be estimated through formula (8) using the same procedure adopted
in the previous section, where simulations were used. Fig. 12
shows the application region and the performance curve for the
case in which the time-delay relay setting is adjusted equal to
59.7 Hz, 100 ms. This figure was determined by using formula
(8). It can be verified that this setting does not violate the frequency-tripping requirements and minimize the critical active
VIEIRA et al.: PERFORMANCE OF FREQUENCY RELAYS
power imbalance. This result is similar to that obtained in Section V-B through simulation (Fig. 8).
ACKNOWLEDGMENT
The authors would like to thank Dr. Z. Huang of the Energy
Science and Technology Division, Pacific Northwest National
Laboratory, for his comments and help during the development
of this work.
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Walmir Freitas (M’02) received the Ph.D. degree in electrical engineering from
the State University of Campinas, Campinas, Brazil, in 2001.
From 2002 to 2003, he was a Post-Doctoral Fellow at the University of Alberta, Edmonton, AB, Canada. Currently, he is an Assistant Professor at the
State University of Campinas. His research interests are power system stability
and control along with distributed generation.
REFERENCES
[1] IEEE Standard for Interconnecting Distributed Resources With Electric
Power Systems, IEEE Std. 1547™, Jul. 21, 2003.
[2] G59/1 Recommendations for the Connection of Embedded Generating
Plant to the Regional Electricity Companies Distribution Systems, 1991.
[3] “Impact of Increasing Contribution of Dispersed Generation on the
Power System,” CIGRÉ, Working Group 37.23, 1999.
[4] “Dispersed Generation,” CIRED, CIRED Working Group 4, 1999.
[5] N. Jenkins, R. Allan, P. Crossley, D. Kirschen, and G. Strbac, Embedded
Generation, 1st ed. London, U.K.: Inst. Elect. Eng., 2000.
[6] W. Freitas, Z. Huang, and W. Xu, “A practical method for assessing the
effectiveness of vector surge relays for distributed generation applications,” IEEE Trans. Power Del., vol. 1, pp. 57–63, Jan. 2005.
[7] P. Kundur, Power System Stability and Control. New York: McGrawHill, 1994.
Jose C. M. Vieira (S’97) received the M.Sc. degree in 1999 from the State
University of Campinas (UNICAMP), Campinas, Brazil, where he is currently
pursuing the Ph.D. degree.
From 1999 to 2003, he was a Consulting Engineer with FIGENER, Sao Paulo,
Brazil. His research interests are distributed generation, power system control,
as well as dynamic and optimal power flow and energy markets.
Wilsun Xu (M’90–SM’95–F’05) received the Ph.D. degree from the University
of British Columbia, Vancouver, BC, Canada, in 1989.
From 1989 to 1996, he was an Electrical Engineer with BC Hydro, where he
was responsible for power quality and voltage stability projects. He is currently
an Adjunct Professor at Shandong University, Shandong, China, and a Professor
at the University of Alberta, Edmonton, AB, Canada. His main research interests
are power quality, voltage stability, and distributed generation.
Andre Morelato (M’89) received the Ph.D. degree in electrical engineering
from the State University of Campinas (UNICAMP), Campinas, Brazil, in 1982.
Currently, he is a Full Professor of Electrical Engineering with the Department of Electrical Energy Systems, UNICAMP. From 1991 to 1992, he was with
Hitachi Research Laboratory, Hitachi Ltd., Hitachi City, Japan. His research interests are power system control and stability, distributed generation, and parallel processing applications.