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IEEE TRANSACTIONS ON INDUSTRIAL INFORMATICS, VOL. 11, NO. 6, DECEMBER 2015
Adaptive Roles of Islanded Microgrid Components
for Voltage and Frequency Transient Responses
Enhancement
Hebatallah M. Ibrahim, Mohamed Shawky El Moursi, Senior Member, IEEE,
and Po-Hsu Huang, Student Member, IEEE
Abstract—This paper introduces a novel framework of coordinated voltage and frequency control strategy for islanded
microgrid (MG) operation. The proposed control schemes rely
on local measurements as communication-free control approach.
Therefore, the distributed controllers of the MG components have
been deployed based on their slow, medium, and fast dynamic
responses to maintain the voltage and frequency in adherence to
IEEE Standards 1547 and 929. The various voltage and frequency
control responses associated with reactive power management
scheme are efficiently utilized based on well-defined states of operation and transient management scheme. In each state, the roles of
each device for voltage and frequency regulations are defined with
its regulation capability, and response time based on its local measurements. Consequently, the fast reactive power compensation
and rapid frequency regulation are ensured based on the inverterbased devices at challenging operating conditions. As a result,
the proposed control strategy improves the voltage and frequency
regulation, transient response, and MG stability. A comprehensive simulation study has verified the superior performance of the
communication-free approach during steady state and in response
to severe disturbances.
Index Terms—Communication-free coordinated voltage and
frequency control, dynamic reactive power reserve, islanded
microgrid (MG), MG stability, transient response.
I. I NTRODUCTION
T
HE CONCEPT of microgrid (MG) in which renewable energy resources (RESs), diesel generator (DZ), and
energy storage systems (ESSs) can be conjugated and integrated to the grid has been growing in importance to cope
with the increasing environmental and resources is problems
[1]. Extensive studies have been done on MGs to ensure their
stability and reliability in supplying electrical power with a
Manuscript received December 24, 2014; revised May 12, 2015 and June 29,
2015; accepted September 06, 2015. Date of publication September 16, 2015;
date of current version December 02, 2015. Paper no. TII-14-1423.
H. M. Ibrahim is with the Department of Electrical Engineering and
Computer Science, Masdar Institute of Science and Technology, Abu Dhabi,
United Arab Emirates.
M. S. El Moursi is with the Department of Electrical Engineering
and Computer Science, Masdar Institute of Science and Technology,
Abu Dhabi, United Arab Emirates. He is currently on leave from the
Faculty of Engineering, Department of Electrical Power Engineering,
Mansoura University, Mansoura, 35516, Egypt (e-mail: melmoursi@masdar.
ac.ae).
P.-H. Huang is with the Department of Electrical Engineering and Computer
Science, Massachusetts Institute of Technology, Cambridge, MA 02139 USA.
Color versions of one or more of the figures in this paper are available online
at http://ieeexplore.ieee.org.
Digital Object Identifier 10.1109/TII.2015.2479580
large amount of intermittent renewable energy resources. To
allow integrating more distributed generation (DG)-based RESs
to MGs, some measures should be taken into consideration
according to the IEEE Standards 1547 and 929 [2], [3] to
ensure the reliability and stability of the grid-tied MG operations. However, these voltage and frequency standards will
be very conservative to the islanded MG. Thus, it requires a
well-defined control structure and actions to manage the MG
dynamics and transient operation. Therefore, two control levels
must be implemented to ensure the stability of the MG islanded
and grid-tied modes of operation which are primary control
(local control) and secondary control (centralized control) [1].
Primary control is mainly devoted to maintain the local variables on site such as voltage and frequency within the standard
limits involving control loops for current injections and droop
control [1], [4]–[6]. As for the secondary control level, it is
dedicated for controlling the system voltage profile and frequency to maintain the MG parameters within the permissible
operational limits. Hence, the secondary level mainly depends
on the communication between the generation units to achieve
the proper coordination in regulating the active and reactive
power flow. Many studies have been carried out using different communication techniques to enhance the reliability of
the system performance [7]–[17]. A simple coordinated control
scheme was proposed in [7] to maintain a constant output power
from a hybrid MG consisting of multiple photovoltaic photo
voltaic (PV) arrays integrated with a DZ. However, it required
a high-speed communication network with the addition of measurement units, data unit, and a battery system to each of the
PV systems, adding up the total system cost. The studies carried out in [8] and [9] proposed a high-speed communication
interface to coordinate between the DERs operation in order to
sustain the power system stability.
The voltage problems in the distribution network with penetration of DGs and MGs have been tackled in the literature by
means of coordinating voltage control [18]–[21]. The coordinated voltage controllers are structured in different combination
of voltage control devices such as static synchronous compensator (STATCOM) with capacitor (CAP) banks, on-load tap
changer (OLTC) with static var compensator (SVC) for the aim
of enhancing the voltage regulation [19]–[21]. However, these
coordinated controllers did not consider the proper utilization of
response time and maximizing the fast dynamic reactive power
reserve to react during severe system disturbances. In [22]–[24],
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IBRAHIM et al.: ADAPTIVE ROLES OF ISLANDED MG COMPONENTS
the DGs have been utilized with their ancillary service of voltage controllers to regulate the voltage profile within acceptable
operating criteria. Therefore, the coordination between the DGs
and OLTC is proposed with managing the active and reactive
power generation from DGs to achieve an effective voltage
regulation. This coordinated voltage control has inquired high
bandwidth communication infrastructure resulted in increasing
the system complexity [25]–[27].
In [28], a new method was proposed to minimize the requirement of communication infrastructure by employing the state
estimator. The coordinated voltage control based on multiagent
system has been deployed among the OLTC, CAP banks, and
DGs. The OLTC was controlled based on a line drop compensation scheme so that few RTUs were installed at selected buses,
mainly for the DGs and CAP banks; also, the voltage profile
along the feeder was estimated. The measured and estimated
voltages at all buses have been processed to identify the pilot
bus to control the OLTC. Consequently, the generation status
of the DGs has been accounted in controlling the OLTC to
avoid the violation of operating voltage criteria along the feeder.
Also, the coordinated voltage controller in the distribution network with the penetration of DGs and MG was considered as
an important optimization problem formulation. In this context,
several optimization techniques with different objective functions such as minimizing the voltage deviation, system losses,
and reducing the tap movements and switching CAP banks have
been deployed [29]–[41]. The voltage control for the islanded
MG becomes a challenge due to the low X/R ratio so that the
intermittency of renewable-based DGs will significantly impact
the voltage profile. Therefore, a robust voltage controller should
be developed to ensure higher system stability by maximizing
the fast dynamic reactive power reserve. Hence, the coordinated
voltage controller is required to manage the reactive power at
each component of the MG to react effectively during the system disturbances. Such controller has been developed in the
literature based on centralized concept with a very complex
communication infrastructure resulting in increasing the cost
and complexity of the MG.
A coordinated voltage control based on meta-heuristic
approach was proposed in [10]. Evolutionary particle swarm
optimization (EPSO) algorithm was used to mitigate between
voltage/VAR controls issues at medium voltage (MV) levels.
The proposed algorithm was based on artificial neural network (ANN) as a secondary level to reduce the computational
time. However, a communication infrastructure and the proper
training of ANN are required to achieve optimal coordination. A control scheme for the state-of-charge (SOC) of an
ESS has been proposed in [12] to switch from fixed power
control to voltage/frequency control when the MG mode of
operation changes from grid-tied mode to islanded mode. The
concept was based on exchange of information between the
DG units and ESS connected to the MG. In [13], a new model
predictive control algorithm was employed to tackle the steadystate and transient control problems of a hybrid MG. Thus,
an energy management system (EMS) was needed to coordinate between the parallel operations of different DG units,
whereas the important parameters were sent to a centralized
server for processing. All these studies required high bandwidth
communication system as its secondary level. Despite the fact
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that using a communication level is important in enhancing the
system performance, any malfunction in this level will lead to
the entire system failure. Therefore, researchers started working on control techniques employing no communication link.
Load sharing has been proposed in [14] to maintain the stability of MG without communication link. However, it did
not achieve the proper system coordination and regulation in
response to severe system disturbances. A study carried out in
[15] proposed installing ESS in each DG to mitigate the load
and generation changes and such a configuration was found
to be very costly. In [16], one ESS has been integrated to
the MG enhancing frequency stability. However, this method
needed communication. A study carried out in [17] proposed
a power-sharing technique to be employed for voltage source
converter (VSC)-based MGs. This technique ensured the active
power stability (frequency stability) without communication
link. However, it has not covered the voltage stability and
reactive power management.
This paper introduces a communication-free coordinated
voltage and frequency technique to enhance the dynamic and
transient performance in response to severe system disturbances. The MG employed in this study integrates a doubly
fed induction generator-based wind turbine (DFIG-WT), a PV
power plant, a battery energy storage system (BESS), a CAP
bank, and a DZ. The distributed controllers of the MG components have been utilized based on their slow, medium, and
fast dynamic responses to maintain the voltage and frequency
in adherence to IEEE Standards 1547 and 929 as conservative operation limit for islanded MG. The adaptive roles of
each device for voltage and frequency regulations are deployed
based on its regulation capability and response time in steadystate, dynamic, and transient conditions. The active and reactive
power management schemes are tested in all states of operation
in the view of achieving fast voltage and frequency regulations, maximizing the fast dynamic reactive power reserve
and enhancing the system stability. Consequently, the performance is evaluated with considering conservative operational
voltage and frequency constraints to demonstrate the superior
performance of the communication-free control strategy for
islanded MG.
This paper is organized as follows. Section II provides the
configuration of the MG under study. Section III explains
the droop scheme applied to the MG components. In Section
IV, the proposed framework control strategy is demonstrated.
Finally, Section V provides the simulation results based on
PSCAD/EMTDC, verifying the performance of the proposed
control strategy.
II. I SLANDED MG S YSTEM D ESCRIPTION
The MG under study consists of DFIG-WT, PV, BESS, CAP
bank, DZ generator, an induction motor, and several fixed loads
that used to test the over frequency (OF), under frequency (UF),
over voltage (OV), and under voltage (UV) states of operation. The parameters of the MG components and controllers
are given in the Appendix as shown in Tables I–IV. The PV
and BESS are connected through dc–ac inverters, three-phase
step-up transformers and cables to the 11-kV bus as shown in
Fig. 1. Each of DFIG-WT, DZ generator, and induction motor
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IEEE TRANSACTIONS ON INDUSTRIAL INFORMATICS, VOL. 11, NO. 6, DECEMBER 2015
Fig. 1. Configuration of the MG under study.
Fig. 2. Nine states of operation for the MG.
is connected to the 11-kV bus through a three-phase step-up
transformer and cables as illustrated. A three-phase step-down
transformer 132 kV/11 kV is used in the connection between
the utility grid and MG with islanding capability using the main
circuit breaker (CB1). The cases presented in this paper are carried out based on an islanded MG so that CB1 will be opened.
The performance of MG will be tested during islanded mode in
response to UF, OF, UV–UF, UV–OF, OV–UF, and OV–OF with
and without employing the proposed control strategy as defined
in Fig. 2.
III. D ROOP -BASED VOLTAGE AND F REQUENCY
C ONTROLLERS
MGs require different operation and control methods than
strong utility grids. Voltage and frequency control are important
for ensuring the stability especially for the islanded MGs with
employing effective droop controllers [44]–[45]. Therefore, a
proper coordinated control scheme between the DG units integrated in the MG is needed. Decentralized droop controllers
are developed for proper coordination between the RES-based
generation units, BESS, and DZ generator; the controllers’ setpoints are chosen depending on the local measurements of the
voltage and frequency during both steady-state and dynamic
Fig. 3. QV droop controllers. (a) For synchronous-based machines. (b) For
inverter-based devices (DFIG-WT, PV, and BESS).
conditions. The proposed control scheme consists of droop
controllers whose parameters are selected according to the reactive and active power supply capability by the DG units. This
method coordinates the active and reactive power flow in the
MG for enhancing the voltage and frequency profiles at point
of common coupling (PCC).
Two droop control strategies have been developed in this
paper for voltage and frequency regulations. Starting with the
voltage droop, for reactive power in an MG, the following
requirements should be satisfied, maintaining the bus voltage
within the specified limits and avoiding the reactive power circulation among the sources. To satisfy these requirements, a
self-adjusting control scheme for proper reactive power coordination between the DG units integrated to this MG is required.
Consequently, the controllers have been implemented in the PV,
DFIG-WT, DZ generator, and BESS based on voltage droop
control to accurately share the reactive power needs. As can
be seen from Fig. 3(a), the voltage droop scheme has been
implemented for the inverter-based devices to inject the reactive power when the voltage at the PCC falls below 1 p.u. or
to absorb the reactive power once the voltage increases over
1 p.u. As for the synchronous-based machines like the DZ
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IBRAHIM et al.: ADAPTIVE ROLES OF ISLANDED MG COMPONENTS
Fig. 4. Pf droop control. (a) For BESS. (b) For PV. (c) For DZ generator.
generator, the voltage droop control scheme was considered to
avoid overexcitation as shown in Fig. 3(b).
The frequency droop scheme was implemented in this paper
for proper active power coordination between the DG units integrated to the MG. Thus, the droop control has been modified for
the BESS to accurately share the active power demand from the
loads. As can be seen from Fig. 4(a), for the BESS the droop
control is designed to regulate the frequency within a range
of 1.008–0.99 p.u. Nonetheless, for the PV system the power
curtailment loop starts curtailing the active power when the frequency reaches above 1.002–1.008 p.u., where at 1.008 p.u.,
the PV power is completely inhibited as shown in Fig. 4(b).
The frequency droop control is also implemented with the DZ
generator for appropriate active power sharing between the DG
units in the MG as shown in Fig. 4(c). Hence, the DZ generator
operates at rated capacity when the frequency is 0.99 p.u. and
decreases till it reaches 30% of its full capacity at 1.002 p.u.
The simulation studies will verify the performance of the proposed method in maintaining the voltage and frequency profiles
within the standard limits under the aforementioned nine states
of operation.
The thresholds and limits of the reactive current support
from the invert-based DGs have been identified to achieve
the desired voltage and frequency regulation according to the
IEEE Standards 1547 and 929. The proposed CVC relies on
the adjustment of the reactive power/current support from the
inverter-based DGs during steady state with minimum loading to react with full reactive power/current capacity during
severe system disturbances. Therefore, a hard limit of 40%
has been imposed on the reactive current support from the PV,
DFIG-WT, and BESS to force the CAP banks (slow response
device) to take more steps and provide sufficient reactive power
compensation during normal operation. Thus, the thresholds
of the hard limits have been determined with considering the
following aspects.
1) The load flow analysis of the MG is conducted at peak
load with the presence of CAP banks, BESS, PV, DFIGWT, and DZ and the voltage profile at the PCC is
evaluated.
2) The power factor of the inverter-based DGs is adjusted to
±0.95 (maximum) and the mechanically switching CAP
banks in association with the DZ are used to regulate
the voltage at PCC within the operating voltage criteria
(0.9–1.1 p.u.). The % of the hard limits of the reactive
power/current compensation at the inverter-based DGs is
gradually increased until the voltage is regulated to the
permissible operating range.
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3) The previous two steps should be carried out with considering the worst/challenging operating conditions as
follows.
a) The inverter-based DGs are generating the full
active power that allows limited reactive power
compensation with the defined pf range ±0.95.
b) The MG is operated at minimum SCR and X/R.
4) The hard limits are not applied in the inverter-based DGs
for the inductive mode of operation to allow maximizing
the fast dynamic reactive power reserve to react during
system disturbances. In this context, the power flow analysis is carried out again at minimum loading condition of
the MG with freezing the CAP banks regulation in case
of overvoltage. Hence, the inverter-based DGs operate in
inductive mode of operation to regulate the voltage within
the operating voltage range resulting in maximizing the
fast dynamic reactive power reserve.
5) Finally, the percentage of reactive power/current compensation during steady-state operation is adjusted.
6) Also, the upper and lower thresholds of the frequency
controllers were chosen to maintain the islanded MG frequency in steady-state, dynamic, and transient operations
within the range defined in the IEEE Standards 1547 and
929. Therefore, the proposed control strategy is developed to achieve fast frequency regulation by relying on
the BESS and PV during dynamic operating conditions
and DZ generator at steady-state condition.
7) Under steady-state operating conditions, the SOC of the
BESS is set to be between 40% and 80% to ensure the
maximum efficiency throughout the battery lifetime.
8) When the MG experiences OF, the SOC upper limit is
released to 90% to allow the BESS to further charge until
the frequency profile is regulated, DZ generator reduces
its operation to 30% (minimum allowed loading condition) and the PV starts curtailing active power until the
frequency profile is regulated.
9) During UF operating conditions, the SOC lower limit is
released to further supply the MG with active power and
the DZ generator operates at its rated capacity.
IV. F RAMEWORK FOR C OORDINATED VOLTAGE AND
F REQUENCY C ONTROL S TRATEGY (CVC AND CFC)
A coordinated voltage and frequency control scheme is
applied to this MG to regulate the voltage and frequency
without any means of communication links between MG components shown in Fig. 1. The system is designed to provide
slow and medium speed response, using low-pass filters (LPFs),
for the CAP banks and DZ generator, respectively, and fast
response for inverter-based DG units. Therefore, it achieves
different regulation bandwidths dedicated by the decentralized
voltage controllers and reactive power management scheme
according to the adaptive reactive current limits in steady-state
and transient operations. The four main states and the actions
taken by each DG unit under the proposed control scheme are
shown in Fig. 5. The state detector is used to identify which
state the MG is experiencing based on the local measurements
at each device. If the MG is under steady-state conditions, the
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addition to this is the assistance from the PV system that
starts curtailing power to maintain the frequency profile
within the permissible limits.
The combined states of operation such as UV-UF, UV-OF,
OV-UF, and OV-OF will consider the defined rules from individual states. As per the flowchart shown in Fig. 6, the control
scheme imposed on each of the devices integrated in the MG is
explained as follows.
A. BESS Model
Fig. 5. State detector flowchart.
PV, DFIG-WT, and BESS are limited to inject maximum of
40% reactive current of their available reactive current. During
steady-state and OV conditions, the maximum reactive current allowed to be absorbed by the inverter-based devices is
released to 100% for inductive mode of operation to maximize
the dynamic reactive power reserve of the MG as shown in
Fig. 5. In addition to that, the SOC of the battery is limited
between 40% and 80% to ensure proper efficiency throughout
the battery lifetime.
Under dynamic-state conditions, a control scheme is
approached to maintain the voltage and frequency of the MG
within the allowed limits approved by IEEE 1547 Standard.
Thus, the actions taken for the defined states of operation are
described as follows.
1) Under the UV state, the PV, DFIG-WT, and BESS are
allowed to inject up to 100% reactive current as shown in
the flowchart in Fig. 6 to enhance the transient response
and voltage profile. Meanwhile, the DZ generator supports by increasing its excitation operation and the CAP
bank increases the number of steps to support the reactive
power deficiency.
2) When the UF state is detected, the BESS and DG act to
maintain the frequency within the allowed standard limits.
The DZ generator operates at its rated capacity and the
BESS releases the lower limit of the SOC to 20% instead
of 40% to compensate the active power shortage.
3) In addition, when OV state is triggered, the CAP bank
will freeze the number of the steps to maximize the fast
dynamic reactive power reserve and the DZ generator
excitation operation is then reduced and the inverterbased RESs may operate in inductive mode of operation
and absorb the reactive power.
4) Finally, when the OF state is detected, the BESS will
increase the SOC upper limit to 95% so as to buffer more
active power, so that the OF situation can be mitigated. In
The BESS model is designed according to Li-ion battery
parameters. The model was integrated with a dc-link capacitor,
a three-phase inverter, an ac filter, and a step-up transformer.
The BESS model of 1.5 MWh consisting of 147 batteries in
series and 3780 in parallel is developed in PSCAD/EMTDC,
shown in Fig. 1. To achieve separate active and reactive power
control, a decoupled current control is implemented for the
inverters. Fig. 7(a) shows the decoupled current control implemented for the inverter-based BESS model and the Fig. 7(b) for
the inverter-based PV. The direct axis (d) is used to represent
the active power component and the quadrature axis (q) is used
to represent the reactive power component.
Fig. 7(a) and (b) is provided to understand how the proposed scheme is applied to the controllers under study; it can
be observed from Fig. 7(a) and (b) that the voltage measured
(Vm ) at the low-voltage side of the transformers is compared
to the reference voltage (Vref ) value which is 1 p.u. and the
error is processed by the PI controller to determine the current
value to be injected to or received from the MG. A current limiter is employed for a proper active and reactive power sharing
between the DG units under steady-state and dynamic conditions. Focus on Fig. 7(a) to explain how the BESS control
model works; if the voltage at the PCC is less than 0.9 p.u., then
BESS reactive current component will be released to 100%.
If not, then the BESS reactive current component (Iq ) will be
limited to 40%. Nonetheless, the frequency at the PCC is measured; if the frequency was measured to be greater than 1.008
p.u., the BESS SOC limit will be released to 95%. If the frequency was measured to be lower than 0.95 p.u., the BESS SOC
lower limit will be released to 20%. The BESS frequency control droop strategy is designed to regulate the frequency within
1.008 and 0.99 p.u. The voltage droop scheme implemented
for BESS is to regulate injecting the MG with reactive current
as the voltage at the PCC falls below 1 p.u. and receiving the
reactive current as the voltage increases over 1 p.u.
B. PV System
The model used in this study integrates PV system of 8 series
and 20 parallel modules, a dc-link capacitor, a dc–dc boost
converter, a three-phase inverter, an ac filter, and a step-up transformer. The PV system’s reactive power loop reacts to maintain
the voltage within the allowed limits specified by the control
strategy, similar to the BESS shown in Fig. 7(b). The control of
the PV inverter is based on decoupled current control loops to
achieve active and reactive power control through dq currents
separately as described in [41]–[43]. The developed model is
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IBRAHIM et al.: ADAPTIVE ROLES OF ISLANDED MG COMPONENTS
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Fig. 6. Flowchart for a framework control strategy for coordinated voltage and frequency controllers of DG units and BESS.
aggregated and scaled up to the desired capacity as shown in
Fig. 1. If the OV condition is triggered, the PV reactive current
component limit to be absorbed (inductive mode) has a fixed
limit of 100% to maximize the dynamic reactive power reserve
at steady-state and OV conditions.
Regarding Fig. 7(b), if the frequency crosses 1.002 p.u., the
PV power will be curtailed to support in regulating the frequency profile. Frequency droop control has been implemented
in the PV model to curtail the active power as the frequency
increases from 1.002 to 1.008 p.u., where at 1.002 p.u. and
below, the PV injects active power at its rated capacity and at
1.008 p.u., the PV power is completely curtailed as can be seen
from Fig. 7(b). Finally, a supplementary power curtailment loop
is employed in the PV controller to allow the curtailing capability of the PV power when the OF state is triggered. Also, the PV
reacts to maintain the voltage within the allowed limits. If OV
condition is triggered, the PV reactive current component limit
to be received has a constant limit of 100% to maximize the
reactive power reserve at steady-state condition as well as OV
condition. If UV condition is triggered, the PV reactive current
component to be injected to the MG is released to 100%.
C. DFIG-WT Model
The wind turbine generator (WTG) used in this study is
DFIG-WT rated at 0.9 MVA. The WTG model employs a
wound rotor induction generator and a back-to-back converter
based on decoupled current control. The converters are rated at
30% of the WTG-rated capacity and modeled as controlled voltage sources [46]. The rotor-side converter (RSC) is dedicated
to control the generator electromagnetic torque so as to adjust
the speed of the generator to reach the maximum power point;
the rotor-side converter is also used to regulate the voltage
[47], [48]. The model is set to maintain the voltage within the
standard limits as PV and BESS. The grid-side converter is connected to the dc-link and dedicated to regulate the active power
flow to maintain the dc-link voltage constant. Nonetheless, the
grid-side converter (GSC) plays a role in exchanging reactive
power with the grid. The reactive current references of the RSC
and GSC are restricted with the limits based on the defined
operation shown in Fig. 6.
D. DZ Generator and CAP Bank Models
The DZ generator model is rated at 1 MVA with implicit
transformer and the CAP bank of 20 steps is rated at 1.2
MVAR; both models are equipped with the LPF to delay the
voltage signal reaching the CAP bank and DZ generator to utilize the DG units connected to the MG according to transient
and steady-states analysis. The DZ generator and CAP bank
are controlled in a way to achieve the fast response from the
inverter-based DGs. Thereafter, inverter-based DG is unloaded
due to the delayed regulation actions from DZ generator and
CAP banks that have been achieved by deploying the LPFs.
Also, if the OV condition is triggered, the DZ generator reduces
its excitation operation and the CAP bank freezes the capacitor
steps to maximize the fast reactive power reserve. However, if
the UV condition was triggered, the DZ generator increases its
excitation and the CAP bank increases its steps based on the
local voltage control. For the frequency regulation, under UF
cases, the DZ generator operates at its rated power to supply the
MG with active power, if the OF condition is triggered, instead
the DZ generator reduces its active power up to the minimum
loading condition of 30% of its rated capacity.
V. E VALUATION OF THE P ROPOSED C ONTROL S TRATEGY
This chapter investigates four case studies to test the MG performance under dynamic and transient states. First, two case
studies are presented to verify the actions taken by the BESS
and PV models in response to OF and UF operating conditions. Second, a case study will be carried out combining two
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Fig. 8. Frequency profile at the PCC in p.u.
Fig. 9. BESS SOC in (%).
in Section IV and on an MG only employing control loops for
current injection and droop control (scenario two).
A. MG Performance Under OF Operating Condition
The OF case is first simulated by disconnecting a load rated
at 0.3 MW at 400 s. As can be seen from Fig. 8, the frequency
in scenario 2 reaches up to 1.108 p.u. and violates the IEEE
1547 Standard by having the frequency above 1.008 p.u. for
more than 0.16 s. However, the frequency response for scenario 1 fulfills the standard without exceeding 1.008 p.u. The
OF condition is triggered when the SOC reaches 80% to test
the proposed CFC that reacts due to the OF. Fig. 9 shows how
the SOC value went slightly above 80% caused by a slew rate
block for the d-current component to gradually reach zero to
avoid any sudden spikes in the frequency by a sudden change in
the value of the current charging the BESS. After the OF condition has been triggered, the SOC for scenario 2 already reached
its upper limit preventing the BESS from charging anymore.
However, for scenario 2, the SOC upper limit was released to
95% allowing the BESS to charge until the operating conditions
are restored to normal. As the load demand on the MG remains
lower than the generation capacity till the end of the simulation, the frequency fails to be maintained at 1 p.u. for scenario
2. However, for scenario 1, the BESS will keep on charging as
shown in Fig. 9 until the load demand and generation capacity
are balanced.
B. MG Performance Under UF Operating Condition
Fig. 7. Inverter controllers for BESS and PV power system. (a) BESS inverter
controller incorporating the droop controller. (b) PV inverter control incorporating the droop and power curtailment controller at OF operation.
of the four operating conditions mentioned earlier as UF–UV,
OF–OV, OF–UV, and UF–OV. Finally, the MG performance
will be tested under transient condition of a three-phase-toground fault, which is applied at PCC and lasts for 140 ms. Each
of the case studies is carried out on an MG employing the proposed CVC and CFC control scheme (scenario one) introduced
To test the system performance under UF condition, a load of
0.105 MW is suddenly connected to the MG at 400 s in a different simulation case. It can be observed that the frequency profile
for scenario 1 is significantly enhanced than the frequency profile for scenario 2, as shown in Fig. 10. When the UF operating
condition was detected, the frequency for scenario 1 dropped
to 0.96 p.u. not violating the IEEE 1547 Standard (for power
system greater than 30 kW). However, the frequency profile for
scenario 2 dropped below 0.95 p.u. for 2.5 s, violating the IEEE
1547 Standard as the system failed to regulate the frequency
back above 0.95 p.u. for more than 0.16 s. Since the proposed
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IBRAHIM et al.: ADAPTIVE ROLES OF ISLANDED MG COMPONENTS
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Fig. 10. Frequency profile at the PCC (FPCC ) in p.u.
Fig. 11. BESS SOC in (%).
Fig. 12. Frequency profile of the MG in p.u.
control strategy allows the SOC lower limit to be released from
40% to 20%, the BESS is allowed to discharge further if the
system generation capacity could not meet the load demand. It
can be observed from Fig. 11 that the battery cells in both cases
are set to reach the minimum SOC limit before the UF operating condition is triggered at 400 s. The SOC limit shown in
Fig. 11 goes slightly below 0.4 for both scenarios before triggering the UF condition due to the slew rate block employed
with the real current component to avoid sudden change in the
current injected to the MG causing fluctuations in the frequency
profile. After triggering the UF operating condition, it can be
observed from Fig. 11 that the SOC minimum limit has been
released for scenario 1 to allow the battery to further discharge,
whereas for scenario 2, the SOC remained the same so that the
BESS does not participate into the frequency regulation.
C. MG Performance Under UF–UV, OF–OV, OF–UV,
and UF–OV Operating Conditions
Fig. 13. Voltage profile at the PCC (VPCC ) in p.u.
In this session, the case study carries out the combined states
of operation to further verify the robustness of the proposed
control strategy under dynamic operation. First, the case is simulated without load changing between 0 and 400 s. Thus, it
ensures time for the CAP bank to reach the steady state before
testing individual operating conditions. Also, a base load of
1.8 MW and 0.15 MVAR is connected over the period of the
simulation. At 400 s, load 1 (0.6 MW) and load 2 (0.6 MVAR)
are suddenly connected to the MG to stimulate UF–UV operating conditions. At 700 s, load 1, load 2, and load 4 (0.3 MVAR)
are suddenly disconnected from the MG for testing the OF–OV
operating condition. Later on, at 900 s, load 3 (0.3 MW) disconnects from the MG and load 5 (0.3 MVAR) engages. This
aims to drive the system into the OF–UV operating conditions.
Finally, load 3 connects and load 5 disconnects again causing
UF–OV operating conditions at 1200 s.
Fig. 12 shows the frequency profile for the reported four
cases. To highlight the change of the operation conditions, a
color code is provided with the results to distinguish between
the states. The UF–UV case is stimulated at 400 s; it can be
observed from Fig. 12 that the frequency profile does not violate the standard limit for both scenarios 1 and 2. At 700 s,
the OF–OV case is initiated; the frequency profile for scenario
2 crossed the limit (1.008 p.u.) for 1.3 s (> 0.16 s), thus violating the IEEE 1547 Standard. For scenario 1, the frequency
profile was successfully maintained below 1.008 p.u., thus not
violating the IEEE standards.
In addition, during the OF-UV condition triggered at 900 s,
the system frequency profile for scenario 1 was enhanced
compared to the frequency profile for scenario 2. It can be
observed from Fig. 12 that the frequency profile for scenario 2
crossed 1.008 p.u. for 0.7 s (> 0.16 s) violating the IEEE 1547
Standard. However, the frequency profile for scenario 1 did not
violate the 1.008-p.u. limit. For the last case based on the UF–
OV operating conditions at 1200 s, the frequency profile was
maintained within the limit for both scenarios. All in all, the
system performance without the proposed scheme may violate
the standard, while the CVC and CFC control method ensures
satisfactory performance against load disturbances.
Fig. 13 illustrates the voltage profile at the PCC (VPCC)
under the four examined cases. At 400 s where the UF–UV case
is stimulated, the VPCC profile for scenario 1 and 2 dropped
below 0.9 p.u. for 0.0185 s (< 0.16 s). Thus, neither of the scenarios violated the voltage lower limit specified by the IEEE
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IEEE TRANSACTIONS ON INDUSTRIAL INFORMATICS, VOL. 11, NO. 6, DECEMBER 2015
Fig. 14. CAP bank steps each rated at 0.1 MVAR.
Fig. 15. Active power (P ) flow in the MG (MW).
1547 Standard which is 0.88 p.u. nor the voltage limit specified by the protection settings for WTG 0.9 p.u. At 700 s, the
OF–OV case is activated causing the VPCC profile for both scenarios to rise over 1.1 p.u. for less than 0.16 s, which is allowed
by the IEEE 1547 Standard. At 900 s, the OF-UV case was
triggered causing the VPCC profile for both scenarios to drop
within the allowed limits, thus neither violating the IEEE 1547
Standard nor the protection settings. The last case is triggered
at 1200 which is UF–OV, causing the VPCC profile for scenario 1 to cross the 1.1-p.u. limit for 0.019 s (< 0.16 s), where
the VPCC profile for scenario 2 did not cross the upper voltage level. This shows the robustness of the proposed control
strategy in regulating the voltage profile while maximizing the
reactive power reserve. The above observations can be further
explained by referring to Fig. 14, where it can be seen that the
CAP bank for scenario 1 took four more steps than for scenario
2 at the beginning and nine (equivalent to 0.9 MVAR) toward
the end of the case study. Consequently, the proposed method
maximizes the fast dynamic reactive power reserve by unloading the inverter-based RES devices. Thus, the VPCC profile
remains slightly above 1 p.u. as can be seen in Fig. 13.
Fig. 15 is provided to illustrate the active power flow in the
MG and the interaction between the BESS, PV, wind turbine
(WT), and DZ generator without communication infrastructure.
At 400 s, when the UF–UV case was triggered, both scenarios
reacted similarly as the frequency remained within the lower
Fig. 16. BESS SOC in (%).
limit specified by the control strategy (0.96 p.u.). The BESS
injected active power (PBESS ) instantaneously as per the load
demands, as shown in Fig. 15(a). As a result, the SOC profile decreased for both scenarios as shown from Fig. 16. The
DZ generator took more time to react for both scenarios and
increased PDZ injected to the MG due to the UF case triggered;
as for the PPV, no change can be observed as the PV is already
operating at its rated capacity and the WT did not take part in
regulating the frequency profile as explained earlier as shown in
Fig. 7. For the OF–OV case triggered at 700 s, the PBESS profile
for scenario 1 decreased while remained positive.
However, the PBESS of the second scenario dropped to
slightly below zero since the BESS aims to mitigate the OF case
triggered. The actions taken by the BESS for scenario 1 can
be explained by observing the PPV profile when the frequency
profile reached 1.008 p.u. The PPV curtailment was triggered
instantaneously, as shown in the dashed box in Fig. 15(b), to
mitigate the frequency profile successfully as shown previously
in Fig. 12. The PBESS for scenario 1 provided active power to
smoothen the quick action taken by the PV resulting in a smooth
frequency profile as shown in Fig. 12. However, for the PV
model under scenario 2, the PV curtailment was not triggered,
so this resulted in charging the BESS from the MG; therefore,
the PBESS for the BESS model for the second scenario dropped
below zero. This can be further verified by observing SOC profile for both scenarios in Fig. 16, where the SOC profile for
scenario 1 continued decreasing, thus injecting active power to
the MG. On the other hand, the SOC profile under the second
scenario increased, thus charging and absorbing active power
from the MG. Consequently, this case showed the success of
the proposed control scheme in providing virtual interaction
between the PV and BESS without communication. The DZ
generator took a slow action in comparison to PV and BESS in
decreasing the active power (PDZ) injected to the MG for both
scenarios as shown in Fig. 15(c). Moreover, at 900 s, the OFUV condition was triggered resulting in PV curtailment; the PV
curtailment took place more severely in this case as the generation capacity exceeds the load demand significantly. Therefore,
the BESS started charging, as shown in Figs. 15(a) and 16 to
support the PV system in regulating the frequency profile back
to 1 p.u. The DZ generator took a relatively slow action again
by restoring the PV power so as to support in regulating the
frequency profile.
At 1200, the UF–OV operating condition was triggered; it
can be seen from Figs. 15(a) and 16 that the BESS started discharging and injecting the MG with active power to mitigate
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IBRAHIM et al.: ADAPTIVE ROLES OF ISLANDED MG COMPONENTS
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Fig. 19. Natural resources profiles. (a) Solar radiation. (b) Wind speed.
Fig. 17. Reactive power (Q) flow in MG (MVAR) for the measured QBESS ,
QPV , QDZ , and QWT .
Fig. 20. Voltage at the PCC (VPCC ).
the proposed control strategy in maximizing the fast dynamic
reactive power reserve. The differences are highlighted in the
figure with notations ΔQs , ΔQ1 , ΔQ2 , ΔQ3 , and ΔQ4 (the
subscript “s” refers to steady state). Fig. 18 has been provided
to further verify the reactive power flow in the MG, by showing
the relationship between the Q measurements shown in Fig. 17
and the measured q-current components shown in Fig. 18.
D. Performance of the CVC and CFC with Considering
the Variations in Solar Radiation and Wind Speed
Fig. 18. Measured quadrature current component (Iq) of the inverter-based
DGs in (kA): (a) IqBESS ; (b) IqPV ; (c) IqWTG (GSC) ; and (d) IqWT(RSC) .
the drop in the frequency profile; meanwhile, the PV is operating at its rated capacity and the DZ generator took a slower
action in comparison to the BESS to provide the MG with further PDZ. Finally, Fig. 17 shows the reactive power flow in the
MG for both scenarios, indicating the superior performance of
To test the reliability of the control strategy under generation
changes, the variable solar radiation and wind speed profiles
have been incorporated. Fig. 19(a) and (b) shows the variable
solar radiation and wind speed profiles that have been used in
this case study. The voltage and frequency profiles are shown
in Figs. 20 and 21, respectively. It can be observed that the
performance of the MG under the proposed control strategy
is improved compared to the MG without employing the CVC
and CFC. The frequency profile shown in Fig. 21 for the MG
not employing the proposed control strategy violated the IEEE
1547 Standard for crossing the upper and lower frequency limits (1.008 and 0.95 p.u.) for more than 0.16 s. However, the
frequency profile for the MG following the proposed control
strategy did not violate the limits stated by the IEEE 1547
Standard and showed an improved performance. The voltage
profile was also given to show how the proposed control scheme
succeeded in maintaining a firm voltage profile.
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IEEE TRANSACTIONS ON INDUSTRIAL INFORMATICS, VOL. 11, NO. 6, DECEMBER 2015
Fig. 23. Frequency profile of the MG in p.u.
Fig. 21. Frequency profile of the MG in p.u.
Fig. 24. Voltage at the PCC (VPCC ) profile of the MG in p.u.
Fig. 22. Voltage at the PCC (VPCC ) profile of the MG in p.u.
VI. T RANSIENT P ERFORMANCE OF THE P ROPOSED
C ONTROL S TRATEGY
To verify the reliability and robustness of the proposed control strategy, the MG transient performance has been evaluated
in response to islanding and reconnecting the MG, tripping of
MG components, and three phase-to-ground faults.
A. MG Performance While Islanding and Reconnecting
to the Electric Grid
To verify the reliability of the control strategy on regulating the voltage and frequency when islanding or reconnecting
an MG, a case study has been carried out. The MG presented
earlier is initially connected to the grid, then islanded at 50 s,
and eventually reconnected at 100 s. Figs. 22 and 23 show the
resulting voltage and frequency profiles. The voltage profile
under the proposed control strategy shows an enhanced performance of the voltage profile compared to the scenario without
employing the proposed control strategy, which is shown in the
zoomed in figures shown in Fig. 22. Also, the frequency profile
under the proposed control strategy shown in Fig. 23 indicates
an enhanced performance over the MG without employing the
proposed control strategy.
B. Performance in Response to Tripping BESS
The BESS plays an important role for regulating the frequency and voltage of the MG. Therefore, the performance of
the proposed control strategy has been evaluated in response to
sudden trip of the BESS and the capability of regulating the
voltage and frequency within the acceptable range has been
evaluated. Figs. 24 and 25 show the rapid regulation of the
voltage and frequency while employing the proposed control
strategy and great enhancement of the transient response for the
MG frequency. This enhancement is accounted due to the activation of the PV curtailment that mitigates the excessive power
generation, which is used to charge the BESS before tripping
as shown in Fig. 26. The case without CVC and CFC shows
frequency violation to the IEEE Standards 1547 and 929. Also,
the CVC and CFC serve to maximize the fast dynamic reactive
power reserve in the inverter-based devices by ΔQ1 and ΔQ3
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IBRAHIM et al.: ADAPTIVE ROLES OF ISLANDED MG COMPONENTS
Fig. 25. Frequency profile of the MG in p.u.
1309
Fig. 28. Reactive power compensation from the CAP banks.
Fig. 29. Voltage at the PCC (VPCC ) profile of the MG in p.u.
Fig. 26. Active power (P ) flow in the MG (MW).
Fig. 30. Frequency profile of the MG in p.u.
C. Performance in Response to Tripping PV
Fig. 27. Reactive power (P ) flow in the MG (MVAr).
and to improve the voltage profile at PCC as shown in Figs. 27
and 24, respectively. Thus, the CAP bank provides higher reactive power compensation while employing the CVC and CFC as
shown in Fig. 28. Hence, it helps to unload the inverter-based
DGs to react effectively during system disturbances.
As the PV is participated in voltage and frequency regulation
control strategy, the performance of the proposed control strategy is evaluated in response to tripping the PV to demonstrate
the reliability of the proposed control strategy. The simulation
results show superior performance of the CVC and CFC for
enhancing the transient voltage response and achieving similar
frequency response compared to the case without employing
the proposed control strategy due to the presence of BESS as
shown in Figs. 29 and 30, respectively. The BESS support the
MG with the deficiency of the active power generation with
rapid discharging as shown in Fig. 31. Also, the proposed control strategy maximizes the dynamic reactive power reserve
in the inverter-based DGs by switching more CAP banks as
shown in Figs. 32 and 33, respectively. The aforementioned
tests by alternatively tripping the BESS and PV demonstrate the
superior performance and reliability of the proposed free communication control strategy for achieving fast frequency and
voltage regulation to the islanded MG.
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IEEE TRANSACTIONS ON INDUSTRIAL INFORMATICS, VOL. 11, NO. 6, DECEMBER 2015
Fig. 34. Voltage at the PCC (VPCC ).
Fig. 31. Active power (P ) flow in the MG (MW).
Fig. 35. Frequency at the PCC (FPCC ).
recover after the fault. This study verified the benefit of maximizing the reactive power reserve in enhancing the system
stability and reliability under faulty conditions. The voltage
profile for scenario 1 recovered after the fault and crossed the
upper limit specified by the IEEE 1547 Standard of 1.1 p.u.
for 0.19 s, indicating improved performance of an islanded MG
under three-phase-to-ground faults. For the frequency profile
shown in Fig. 35, the frequency of the MG employing the proposed control strategy crossed 1.008 p.u. for 0.2 s, then was
regulated back to 1 p.u., thus again showing the superior performance of an islanded MG following the proposed control
strategy under three-phase-to-ground fault.
VII. C ONCLUSION
Fig. 32. Reactive power (P ) flow in the MG (MVAr).
Fig. 33. Reactive power compensation from the CAP banks.
D. MG Performance Under Three-Phase-to-Ground Fault
A three-phase-to-ground fault has been stimulated at the PCC
for 140 ms. As illustrated from Figs. 34 and 35, the MG under
scenario 2 went unstable after triggering the three-phase-toground fault. However, the MG under scenario 1 was able to
A communication-free coordinated voltage and frequency
control strategy demonstrates superior performance for maintaining the voltage and frequency profiles within an acceptable
range in various conditions including steady, dynamic, and transient states. The distributed controllers implemented for the
MG components have been utilized efficiently based on their
slow, medium, and fast dynamic responses to act coordinately
during system disturbances. The control strategy managed the
active and reactive power flow and transient response in adherence to IEEE Standards 1547 and 929 and enhanced the system
stability and reliability. Comprehensive case studies have been
carried out and verified the robustness and performance of the
control scheme in the view of transient responses and system
stability. The fast dynamic reactive power reserve capability
and rapid frequency regulation have been demonstrated by the
simulations cases under all operating conditions, including tripping of MG components and three-phases-to-ground faults.
The proposed CVC and CFC control strategy achieves a costeffective solution for islanded MGs without communication
that achieves the centralized features based on decentralized
controllers.
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IBRAHIM et al.: ADAPTIVE ROLES OF ISLANDED MG COMPONENTS
A PPENDIX
TABLE I
P OWER S YSTEM , DZ, DFIG-WT, PV, BESS, AND CAP BANK
PARAMETERS
TABLE II
L OAD PARAMETERS
TABLE III
PV M ODEL PARAMETERS
STC, standard test condition.
TABLE IV
MPPT M ODEL PARAMETERS
1311
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Hebatallah M. Ibrahim was born in Cairo, Egypt,
in 1989. She received the B.Sc. degree in electronics
engineering from German University, Cairo, Egypt,
in 2011, and the M.Sc. degree in electrical power
engineering from the Masdar Institute of Science and
Technology, Abu Dhabi, United Arab Emirates, in
2013.
Her research interests include in microgrid, power
system stability, and control.
Mohamed Shawky El Moursi (M’12–SM’15)
received the B.Sc. and M.Sc. degrees from Mansoura
University, Mansoura, Egypt, in 1997 and 2002,
respectively, and the Ph.D. degree from the University
of New Brunswick (UNB), Fredericton, NB, Canada,
in 2005, all in electrical engineering.
From 2002 to 2005, he was a Research and
Teaching Assistant with the Department of Electrical
and Computer Engineering, UNB. He joined as
a Postdoctoral Fellow with the Power Electronics
Group, McGill University, Montréal, QC, Canada. He
joined Technology R&D, Wind Power Plant Group, Vestas Wind Systems,
Arhus, Denmark. He was a Senior Study and Planning Engineer with
TRANSCO, Abu Dhabi, United Arab Emirates, and was promoted to an
Associate Professor with the Faculty of Engineering, Mansoura University,
where he is currently on leave. He was a Visiting Professor at the Massachusetts
Institute of Technology, Cambridge, MA, USA. Currently, he is an Associate
Professor with the Department of Electrical Engineering and Computer
Science, Masdar Institute of Science and Technology, Abu Dhabi. His research
interests include power system, power electronics, flexible ac transmission system technologies, system control, WT modeling, wind energy integration, and
interconnections.
Dr. El Moursi is currently an Editor for the IEEE TRANSACTIONS
ON P OWER D ELIVERY , an Associate Editor of the IEEE T RANSACTIONS
ON P OWER E LECTRONICS , the Regional Editor for IET Renewable Power
Generation, and an Associate Editor for the IET Power Electronics Journal.
Po-Hsu Huang (S’11) was born in Taiwan, China,
in 1985. He received the B.Sc. degree from National
Cheng-Kung University, Tainan, Taiwan, and the
first M.Sc. degree from National Taiwan University,
Taipei, Taiwan, in 2007 and 2009, respectively, both
in electrical engineering, and the second M.Sc. degree
in electrical power engineering from the Masdar
Institute of Science and Technology, Abu Dhabi,
United Arab Emirates, in 2013. Currently, he is pursuing the Ph.D. degree at the Department of Electrical
Engineering and Computer Science, Massachusetts
Institute of Technology, Cambridge, MA, USA.
His research interests include dc/ac microgrids, power electronics, wind
power generation, linear/nonlinear system dynamics, power system stability,
and control.
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