Performance, Modelling & Simulation of Frequency Relays for Distributed Generation Protection

By:-
Niraj Solanki
Performance, Modelling & Simulation
of Frequency Relays for Distributed
Generation Protection

Contains:-
1) Introduction.
2) Distributed Generation.
3) Introduction about Frequency Relay
Protection.
4) Performance Curves of Frequency Relay.
5) Vector surge relays v/s Frequency Relays.
6) Modeling and Simulation of Adaptive
Frequency Relay for Distributed Generation.
7) Conclusions

Introduction
 This Presentation investigates the efficiency of
under/over frequency relays for protection of distributed
synchronous generators considering islanding detection
and frequency-tripping requirements.
 The idea that frequency relays can replace Vector Surge
Relay for islanding detection purpose.
 presents an adaptive frequency relay model that can
automatically change its settings to accommodate both
modes of operation.(Islanding & With Utility Grid).

 It is a small-scale generation of power, usually from a
renewable resource (or small scale generator) to feed
a nearby load. This concept has become popular in
rural Africa, where access to the Utility network can be
expensive.
 Microgrid: The combination of this distributed
generation and local load
 Islanding Concept.

 All distributed synchronous generators are also
equipped with under/over frequency relays.
 Both the vector surge relay and the frequency
relays operate on the basis of system frequency
deviation.
 But, if the frequency relay can replace the vector
surge relay for islanding detection application.
 The savings can be quite attractive for small-
distributed generators and the protection system
would be much simpler.

 Issues rising from using Frequency-based relay
for anti islanding protection:-
 According to IEEE distributed guide, DG must not be
disconnected due to small frequency variation. If the
relay is set to meet this requirement, it may not detect
islanding condition within time.
 If the relay is set sensitive for islanding detection, It
may also trip the DG due to small frequency
variations.
 Thus, it is important to understand if there is a region
where relay can satisfied both the requirement, if such
a region exist what are its characteristics?

Sections of this presentation:
 to analyze the islanding detection capability of
frequency-based relays.
 the network component models used for frequency
relay.
 comparative study between the performance of
frequency relays (FR) and vector surge relays (VSRs)
for anti-islanding protection.
 the concept of application region where the frequency
relay can be used for anti-islanding protection.

PERFORMANCE CURVES OF FREQUENCY
RELAYS
 The islanding detection capability of frequency-based
relays is know from it’s Performance curve.
 active power imbalance vs. islanding detection time.
 The islanding detection capability of frequency-based
relays is strongly dependent on the active power
imbalance existent in the islanded system, i.e. the
mismatch between load and generation.
 an approach to evaluate the performance of frequency-
based anti-islanding relays is to understand the
relationship between the detection time and active

PERFORMANCE CURVE OF FREQUENCY
RELAYS
•X-axis is the active power imbalance level of the islanded
system referred to the rated MVA of the generator.
•y-axis is the time needed by the relay to operate.
For 400ms

 Network Component Models:
 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.
We =Generator electrical speed

Operation of VSR & Frequency Relay
Frequency Relay Vector Surge Relay
 measure the cycle duration of the
terminal voltage by using some
voltage zero crossing detection.
 The system frequency f is
determined from the generator
electrical speed we
 if a variation of frequency ±∆f
occurs, the frequency relay
becomes active.
 frequency relays can be blocked if
the terminal voltage drops below
Vmin an adjustable level.
 It 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).
 If the variation of the terminal
voltage angle exceeds a pre-
determined threshold, Relay
trip.(Allow 2 to 20°)
 The absolute variation between
these two angles ∆Ɵ = || Ɵ - Ɵ0 ||
 If Ɵ > threshold α and terminal
voltage is larger than Vmin, Realy
will be trip.
The main difference in the operating principles of frequency and vector surge
relays is the reference value used to trigger the relay. While the FR uses a fixed
reference,the rated system frequency (60 Hz ), the reference value used by a
vector surge relay is updated cycle bycycle,

Comparative analysis between frequency
relays and vector surge relays for islanding
detection
 Islanding detection capability of frequency and vector surge
relays is carried out by using the performance curves.(by
dynamic simulation)
 example
 The active power imbalance of the islanded system is
gradually varied from 0 to 1 pu, referred to the MVA rating
of the generator.
 For each case of active power imbalance, dynamic
simulation is conducted to determine the relay detection

 In a 60 Hz system, 1 Hz corresponds to 6 electrical
degrees.
 The critical power imbalances for typical relays settings
considering that the required detection time is 300, 500
or 700 ms are presented in Table .
 Noted that both relays lead to very similar critical power
imbalances.
 The vector surge relay does not offer additional
advantages than the frequency relay for anti-islanding
protection. As a result, there is no need to install a
curves

Performance curves of VSR and frequency
relays.

Application Region of Frequency Relay
 The results shown in previous case indicate that there is a
region where the frequency relay can satisfy both anti
islanding and frequency-tripping requirements.
 graphical methodology that helps to evaluate the frequency
relay settings acceptable for both purposes.
 The application region was obtained by using the
performance curves of the frequency relay.
 Such curves were obtained through dynamical simulation.

 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.
 Performance curve for 3 Hz (57 Hz): it represents the upper
limit of the region. 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.

Formulas to determine the application region of frequency
relays
 By this formulas 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,
 Analytical Formula:
 Considering the system presented in Fig. 2
 at steady state, the mechanical power PM, of the distributed
generator is balanced with the load electrical power PL and
the electrical power PSYS provided (or consumed) by the
power grid. Therefore, the distributed generator rotor
speed ω and angle ∂ are constant. and active power
imbalance is ∆P.
 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
 Where H is Inertia constant,ω0 Synchronous Speed, The rotor
angle Speed ω Can be solved from (1)
 The system angular speed in the time can be represented by
ω = ω0+∆ω

 Equation (4) gives the relationship between frequency deviation
(relay setting), detection time and active power imbalance.
Solving (4) for , we have
 Where ∆ƒ is the relay setting. Frequency relays can be adjusted
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:
 where is tset the time-delay applied. With (6), one can obtain the
detection time versus power imbalance curves and, consequently,

 Modern utilities around the world have started the
implementation of small scale local generation to support
power supply.
 Introduction of distributed generation presents new
challenges and opportunities for electrical engineers.
 The combination of this distributed generation and local
load forms what is known as a Microgrid. A Microgrid is a
smaller power grid that may operate connected to the
utility grid or in isolation. In remote areas it generally
operates in isolation, in what is also known as Islanded
mode.
 Microgrids operate in different modes, for these different
modes the relays are subject to different system
conditions, and it is important that protection systems
Modeling and Simulation of Adaptive
Frequency Relay for Distributed
Generation [3]

 This poses a challenge to frequency protection engineers
because currently frequency relays are non-adaptive,
they operate based on fixed limits and thresholds for
operation. An adaptive relay that can change its settings
to suit the mode of Microgrid operation is advantageous.
 Practical Case :
The system frequency for a South African Microgrid would
be governed by the Distribution Grid Code and relevant
standards that are enforced by the Electricity regulator.
 Power systems often do not operate in ideal
circumstances For this reason Grid codes generally allow
for some deviation in the nominal value

 In South Africa for example the following limitations apply
as listed in Table 1:
 It is evident that the grid code allows for a larger frequency
variation when the Microgrid is operating in islanded mode
than when it is connected to the grid.

FREQUENCY RELAYING
 It can detect whether the system is operating at a lower or
higher frequency compared to the nominal value.
 It can also monitor the rate of change of frequency. If the
frequency goes above or below set limits or fluctuates at
an unacceptable rate (df/dt), this is detected, resulting in
disconnection or load rejection.
 Frequency variations that are large enough to cause
problems are most often encountered in small isolated
networks such as:
A. faulty or maladjusted governors.
B. Serious overloads on a network.
C. Failure of governer.

 Under frequency protection will respond to the falling
frequency on loss of supply.
 Under frequency load shedding is used when the
electricity demand exceeds the generation capability.
 Relays that can detect both over frequency and under
frequency are common in the industry. However these
relays can only accommodate one overfrequency setting
and one underfrequency setting, this is a limitation when it
comes to Microgrid protection because these settings may
need to change based on the mode of operation.
 If a relay is set to grid connected operation mode the non-
detection region will be narrow and set to suit the ±2.5%
variation.

 If a relay is set to grid
connected operation mode the
non-detection region will be
narrow and set to suit the
±2.5% variation.(Fig 1)
while if the relay is set to
island mode of operation the
non-detection zone will be
wider to allow for ±5%
frequency variation.

 ADAPTIVE FREQUENCY RELAY MODEL
 The adaptive relay model was designed as displayed in Fig.

 If there is sufficient variation in system frequency, the
frequency relay becomes active. Frequency relays can be
adjusted using multi-stages; therefore, instantaneous and
time-delay settings can be employed simultaneously.
 The relay is assumed to have a communications connection
to the Static Switch (SS). The information received from the
Static Switch at the point of common coupling is a binary
value, i.e. 0 or 1.
 This will enable the relay to configure its settings to suit the
Microgrid’s mode of operation. If the signal is 0 the Microgrid
is in Island mode, if the signal is 1 it is in grid connected
mode.

 Once the mode of operation has been established the
frequency is read. This system frequency (f) is compared
to the allowed variation limits. If the value of f is within the
non-detection zone, the trip signal is zero. However, if f is
higher than the upper limit or lower than the lower limit, the
relay will attempt to send out a Trip Signal to the circuit
breaker.
 Before the Trip Signal is sent out, the system voltage is
measured. If the terminal voltage drops below an
adjustable level Vmin the relay can be blocked from
operating. This is to avoid, for Example, the activation of
the relay during generator start-up.

TESTING PROCEDURES
 Consider a Power System Model shown in fig.

 A. Test Case 1
 This is an Underfrequency test in Grid connected mode.
Variable load is switched on at 2s and steadily increased;
this was done to create a sudden load pick-up scenario.
This increases the system load until the system becomes
unstable and the frequency starts dropping. It will be at
48.75 Hz that the relay will detect an abnormality and
attempt to protect the Microgrid by opening CB5 and
disconnecting the variable load.
 B. Test Case 2
 This is an Underfrequency test similar to Test Case 1, but
with the Microgrid in Island mode. Again the variable load
is switched on at 2s and steadily increased. This
increases the system load until the system becomes
unstable and the frequency drops. The relay should
trigger CB5 to open once the frequency reaches 47.5 Hz.
The relay will change the underfrequency tolerance after

 C. Test Case 3
 Case 3 is an Overfrequency test in Grid Connected mode.
In this case the simulation starts with the variable load of
2MVA on. At 2s the load is lost causing the generators to
be under loaded. This leads to a system overfrequency. In
this case the Microgrid is isolated from the Utility grid by
opening the Static Switch. This way the Utility will not be
affected by the Microgrid system overfrequency. The SS
should open once the frequency reaches 51.25Hz.
 D. Test Case 4
 This is an Overfrequency test in Island mode. Again the
variable load is lost after 2s. The CB 5 should only open
once the frequency reaches 52.5Hz

 TEST RESULTS AND INTERPRETATION
 A. Test 1
 Once the variable load in the Microgrid was switched on at 2s
and steadily increased, the system became overloaded and
the frequency suddenly dropped. At 48.75Hz the relay
detected this drop. The reason for the frequency dropping
below the limit is because the CB5 did not open
instantaneously because of system delays. While the delays
occurred the frequency dropped further to 47.25Hz. Once the
CB5 was opened and the system frequency was gradually
restored. The system frequency is shown in Fig.

 B. Test 2
 Again the ability of the relay to operate in an
underfrequency situation was tested. The frequency
dropped even further than the previous test because the
Microgrid is operating in Island Mode. This time the
frequency dropped to 46Hz and the frequency was steadily
restored once CB5 was opened. The system frequency for
this test is shown in Fig.7.

 C. Test 3
 To test the overfrequency detection and clearance capability,
the variable load was disconnected to cause a general
system loss of load scenario. Due to the loss of load the
frequency increased and at 51.25Hz the relay triggered the
DG circuit breaker to open. Once the DG is disconnected the
Utility generation and load becomes balanced and the
system frequency is restored as shown in Fig. The measured
frequency rose to 52.9Hz because of system delays between
the relay and CB.

 Test 4
 This test was conducted in a similar manner to test 3,
however this time the Microgrid was operating in isolated
mode, i.e. the SS was already open. The result of Fig.9
shows that once the relay detects the abnormality it opens
CB5 to isolate the variable load. The measured frequency in
this case is 54.4Hz, 1.5Hz higher than the previous test.
This difference is expected due to the higher variation
allowed by the Grid Code in this mode of operation.

Conclusion
s
 Vector surge relays and frequency relays present very
similar performances for anti-islanding detection.
 frequency relays can replace VSR for islanding detection
without adverse implications if proper settings are chosen.
 A use for an adaptive over and under frequency relay, which
can make the protection system more robust and allows the
protection devices to cater for a wider range of abnormal
events which in turn makes the protection system more
reliable.

Reference
s
1) Performance of Frequency Relays for Distributed
Generation Protection by Jose C. M. Vieira, Student Member,
IEEE, Walmir Freitas, Member, IEEE, Wilsun Xu, Fellow, IEEE,
and Andre Morelato, Member, IEEE.(IEEE TRANSACTIONS ON
POWER DELIVERY, VOL. 21, NO. 3, JULY 2006).
2) A Practical Method for Assessing the Effectiveness of
Vector Surge Relays for Distributed Generation
Applications, byWalmir Freitas, Member, IEEE, Zhenyu Huang, Member,
IEEE, and Wilsun Xu, Senior Member, IEEE (IEEE TRANSACTIONS ON
POWER DELIVERY, VOL. 20, NO. 1, JANUARY 2005).
3) Modelling and Simulation of Adaptive Frequency Relaying
for Distributed Generation, By C.Buque, S. Chowdhury, S.P
Chowdhury,
10.1109/AFRICON.2013 .6757837 , IEEE Conference At

Performance, Modelling & Simulation of Frequency Relays for Distributed Generation Protection

Vector Surge Relay
(VSR)[2]
 Vector surge relay is one of the most sensitive frequency
based anti-islanding devices.
 The vector surge relay is used to decouple synchronous
generators from the grid utility in case of grid failure.
 In Islanding condition, the current industry practice is to
disconnect all distributed generators immediately after an
islanding occurrence.( in between 200 to 300 ms after loss
of the main supply).
 Each distributed generator should be equipped with an
islanding detection device. Like,
1. Frequency Relay
2. Vector Surge Relay or Vector Shift Relay

Principle of Vector Surge
Relay:
 Terminology:
 ∆V = voltage drop between the terminal voltage VT and
the generator internal voltage EI.
 Generator current ISG passing through the generator
reactance Xd .
 there is a displacement angle ∂ between the terminal
voltage and the generator internal voltage.
 Phasor diagram is presented in Fig.

EI
VT
∂
∆V
∆∂EI
V’T
∆V’
(a) before the opening of CB (b) after the opening of CB.

 Analyzing such phenomenon in the time domain, the
instantaneous value of the terminal voltage jumps to
another value and the phase position changes.
 The point A indicates the islanding instant.
 The frequency of the terminal voltage also changes.
 This behavior of the terminal voltage is called vector surge
or vector shift. Vector surge relays are based on such
phenomena.
 Vector surge relays available in the market measure the
duration time of an electrical cycle and start a new
measurement at each zero rising crossings of the terminal
voltage.
 The current cycle duration (measured waveform) is
compared with the last one (reference cycle).
 Variation of the cycle duration results in a proportional
variation of the terminal voltage angle ∆∂, which is the

 If the variation of the terminal voltage angle exceeds a
predetermined threshold α, a trip signal is immediately sent
to the CB.
 Range of α allowed By VSR is 2° to 20°.
 Important characteristic of these relays is a block function
by minimum terminal voltage. If the terminal voltage drops
below an adjustable level threshold Vmin , the trip signal
from the vector surge relay is blocked. This is to avoid.
 E.g. During generator startup or short circuits.

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