A Coordinated Voltage and Frequency Control of Inverter Based Distributed Generation and Distributed Energy Storage System for Autonomous Microgrids

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A Coordinated Voltage and FrequencyControl of Inverter Based DistributedGeneration and Distributed EnergyStorage System for AutonomousMicrogridsMostafa I. Marei a & Mohamed H. Soliman aa Electrical Power and Machines Department, Faculty of Engineering,Ain Shams University, Cairo, Egypt

To cite this article: Mostafa I. Marei & Mohamed H. Soliman (2013): A Coordinated Voltage andFrequency Control of Inverter Based Distributed Generation and Distributed Energy Storage System forAutonomous Microgrids, Electric Power Components and Systems, 41:4, 383-400

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Electric Power Components and Systems, 41:383–400, 2013

Copyright © Taylor & Francis Group, LLC

ISSN: 1532-5008 print/1532-5016 online

DOI: 10.1080/15325008.2012.749550

A Coordinated Voltage and Frequency Control of

Inverter Based Distributed Generation and

Distributed Energy Storage System forAutonomous Microgrids

MOSTAFA I. MAREI1

and MOHAMED H. SOLIMAN1

1Electrical Power and Machines Department, Faculty of Engineering,

Ain Shams University, Cairo, Egypt

Abstract Distributed generation and distributed energy storage systems can becontrolled to improve power system stability. This article proposes control strategies

for adopting distributed generation units to autonomous microgrids. The proposeddistributed generation interface is utilized not only to control the active power flow, but

also to provide essential ancillary services, such as voltage regulation and frequencycontrol, to the autonomous microgrid. A coordinated voltage and frequency control

of the inverter-based distributed generation and distributed energy storage system ispresented. Moreover, a frequency estimation algorithm based on orthogonal filters

is adopted for the frequency control loop. One advantage of the proposed controlsystem is its unified structure for the different operating modes. Extensive simulations

of the proposed coordinated control of the inverter-based distributed generation anddistributed energy storage system are conducted to evaluate the dynamic performance

of the proposed microgrid.

Keywords distributed energy storage systems, distributed generation, frequencycontrol, microgrids, voltage regulation

1. Introduction

Distributed generation (DG) systems can provide a number of ancillary services to the

future microgrid. The effect and control scope of these ancillary services on the power

system can be local or global (system wide), depending on their penetration level in

the system. Local ancillary services, including voltage regulation, reactive power supply,

and losses reduction, are provided and controlled locally where needed. Global ancillary

services, such as frequency control and active power reserves, affect the whole system

and can be provided anywhere in the power system [1].

Many DG technologies do not use a synchronous generator to convert primary energy

into electricity. DG units, such as photovoltaic (PV) cells, fuel cell, microturbines, and

storage devices, are interfaced via such power electronics converters as voltage source

inverters (VSIs). DGs are often connected to low- and medium-voltage grids [2, 3].

Received 31 July 2012; accepted 10 November 2012.Address correspondence to Dr. Mostafa I. Marei, Electrical Power and Machines Department,

Faculty of Engineering, Ain Shams University, 1 El-Sarayat St., Abbasia, Cairo, 11517, Egypt.E-mail: [email protected]

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384 M. I. Marei and M. H. Soliman

The autonomous (islanded) microgrid is more prone to frequency changes than the

conventional utility grid. In the autonomous microgrid, the variation in the rotational

speed of a diesel generator due to disturbances becomes significantly high. This may cause

large frequency variations that end up in an unstable and insecure microgrid. This is why

future DG systems have to take a dominant part in maintaining microgrid stability [4].

Utilizing the DG interface system to regulate the load voltage was proposed in [5].

In order to control the microgrid frequency, the active power generation of each DG

unit in a microgrid is specified based on a defined power-frequency droop characteris-

tic [6]. In order to improve system stability and power sharing, different droop-based

control methods have been proposed [7–12]. Different power management strategies

were investigated in [13] to assign real and reactive power references for the DG units

to quickly respond to disturbances due to the changes in the microgrid and to restore

frequency of the system. However, droop-based control methods are not feasible for

renewable energy sources due to their non-dispatchable characteristics, which may cause

instability of microgrid. The interface systems of renewable energy sources, such as

wind and solar, are controlled in maximum power tracking mode to yield considerable

economic benefits. Despite reliability and cost issues, centralized and distributed control

of a microgrid based on a communication infrastructure is introduced to improve the

power-sharing and power-quality performance of the system [14, 15].

This article proposes control strategies for adopting DG units to autonomous mi-

crogrids. It presents a DG interface control algorithm for multifunction operation, which

regulates the terminal voltage at the point of common connection (PCC) within the pre-

specified limits [16] and controls the output power from the DG source. Moreover, the

same proposed interface is utilized to control the microgrid frequency. A frequency es-

timation algorithm based on orthogonal filters is adopted for the proposed frequency

stabilization loop.

Installation of distributed energy storage systems (DESS) in the demand side comes

in accordance with customer preference of green energy resources. In addition, they

help in conserving energy and improving reliability. Such energy storage elements have

to be sufficiently large to be capable of compensating load variations and maintaining

frequency stability. Ultracapacitors are characterized by their high power density, which

renders them attractive for high energy storage applications [17, 18].

If the ultracapacitor bank is connected directly to the DC-link of the DESS inter-

face, it must be sized to work at the rated voltage of the DC-link. Furthermore, the

ultracapacitor bank will not be utilized effectively, since the VSI of the DESS interface

cannot work properly at a DC-link voltage lower than the rated value. To overcome

these disadvantages, the ultracapacitor bank is connected through a DC/DC converter to

the VSI. The proposed control system for the DC/DC converter regulates the DC-link

voltage of the DESS interface and controls the ultracapacitor current simultaneously. Con-

sequently, the DC/DC converter enables the effective utilization of the ultracapacitor bank

down to any desired voltage level without exceeding the rated current. In addition, it fa-

cilitates the optimum sizing of the ultracapacitor bank based on the required energy level.

A microgrid that includes a diesel generator, an inverter-based DG, and an inverter-

based DESS is modeled in the PSCAD/EMTDC simulation package (Manitoba HVDC

Research Center, Manitoba, Canada). The DESS interface is controlled to stabilize the

microgrid frequency, while the voltage regulation task is assigned to the DG interface. The

dynamic performance of the proposed system is investigated, and the results are discussed

to demonstrate the potential of the proposed coordinated voltage and frequency control

techniques.

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Coordinated Control of DG and DESS for Microgrids 385

2. The Proposed Coordinated Voltage and Frequency Control

The microgrid considered in this study includes rotating DG, such as a diesel generator

and static DG systems (fuel cells, PV cells, or energy storage devices), that are interfaced

by a VSI. The diesel generator is simulated by a synchronous generator with the following

swing equation:

Pm � Pe DH

�fo

@2ı

@t2C D

@ı

@t; (1)

where Pm is the p.u. input mechanical power, Pe is the p.u. output electrical power, H

is the inertia constant (sec), fo is the nominal frequency (Hz), ı is the power angle (rad),

and D is the p.u. damping coefficient.

The DGs have to work in a coordinated manner using appropriate control systems to

compensate for power oscillations in the microgrid and to regulate the load voltage. The

main function of the DG interface system based on a VSI is to regulate the active power

supplied from the DG to the microgrid. Besides, the VSI can also supply reactive power to

the microgrid to enable unity power factor operation or to regulate the voltage at the

PCC [5]. This article proposes an extension to the functionalities of the DG interface

system to damp frequency oscillations, hence stabilizing the microgrid.

The proposed multifunction coordinated control system for the DG interface is shown

in Figure 1. Two different modes of operation are proposed according to the positions of

the selectors. In mode 1, where the selectors are set at position 1, the direct component

Figure 1. Block diagram of proposed control system for DG interface.

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of the VSI reference current i�

dis assigned to the active power control loop. A simple

proportional-integral (PI) controller is utilized to control the active power fed from the

DG at a desired value, P �. The i�

d limiter is adjusted to prevent overloading the DG

source. Moreover, the quadrature component of the VSI reference current, i�

q , is set to

regulate the PCC voltage at a desired level, V �

PCC , using another PI controller. Based on

the VA rating of the DG interface system, a limiter is designed for the reactive current

component to prevent exceeding the rated current of the VSI. For mode 2, i�

dis set to

regulate the microgrid frequency at its nominal value. In addition, i�

q is set to zero, which

means that the DG interface system becomes dedicated to compensate the load variations.

This mode of operation is responsible for frequency stabilization in an islanded microgrid

or in a traditional network with a high DG penetration level.

Utilizing the inverse Park’s transformation (dq=abc), the converter reference current

I �

c is converted from a synchronously rotating frame to the three-phase coordinates. The

instantaneous phase angle of the PCC voltage vector ‚ is obtained from a phase-locked

loop (PLL) circuit. A current-controlled VSI manages the amount of current Ic injected

to the microgrid. The current-controlled VSI is selected for this application due to its

fast dynamic response, accurate performance, ease of implementation, and insensitivity

to distribution system parameter variations. One advantage of the proposed strategy is

that the structure of the controller remains unchanged for the different operating modes.

The proposed control scheme demonstrates how DGs can contribute to frequency

stability. However, this contribution is limited to active power injection for overloaded

microgrid. The case of a lightly loaded microgrid raises the need for DESS that can store

energy immediately when the microgrid has excess power and release it during load

peaks. The DESS can contribute to the compensation of load variations by either power

injection or absorption. A simple microgrid, shown in Figure 2, is considered to evaluate

the performance of the proposed control systems. The DG interface system is controlled

to feed a constant active power and to regulate the PCC voltage (PV mode) by setting

Figure 2. Configuration of microgrid under study.

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the selector switches in Figure 1 at position 1. Furthermore, the DESS interface system

is set at the frequency control mode by adjusting the selector switches in Figure 1 at

position 2. An ultracapacitor bank is utilized as an energy storage system connected to

the DC-side of the VSI.

For effective utilization of the ultracapacitor bank, a DC/DC converter is utilized to

connect the ultracapacitor bank to the DC side of the VSI. Figure 3 illustrates the proposed

control system for the buck-boost converter to regulate the DC-link voltage and control

the ultracapacitor current. The DC-link voltage is regulated at the required value (V �

dc )

using a PI controller, which generates the reference current of the ultracapacitor bank,

i�

uc. The limiter is set to the maximum continuous current of the ultracapacitor to prevent

overloading the ultracapacitor bank. Finally, hysteresis current control (HCC) is utilized

to generate the switching signals, s and its complement s, for the DC/DC converter.

Using the proposed DC/DC converter system allows discharging the ultacapacitor bank

to any desired voltage level without exceeding the rated current. This action results in

effective utilization of the ultracapacitor bank.

If the DESS interface feeds power to the microgrid, the DC/DC converter operates

in the boost mode. On the contrary, the DC/DC converter acts as a buck converter to

charge the ultracapacitor bank from the microgrid in the case of over-frequency due

to either excess generation or light loading. Charging the ultracapacitor bank is limited

by its maximum operating voltage to avoid a dielectric failure.

Figure 4 shows a flowchart of a proposed supervisory control system to keep the

ultracapacitor voltage vUC in the desired operating range. The ultracapacitor voltage

approaches its rated maximum value when the generated active power exceeds the loading

level. At this condition, the diesel generator receives a control signal to reduce its active

power P �

Diesel to prevent exceeding the maximum voltage of the ultracapacitor bank. If vUC

still approaches its maximum value and the active power of the diesel generator becomes

zero, the supervisory control forces the DG interface to reduce its active power (P �

DG)

until the ultracapacitor voltage stop increasing. On the other hand, if vUC approaches its

minimum value, the generation level needs to be increased. The supervisory controller

takes this action in two levels. First, the DG interface is asked to increase its reference

active power based on the available maximum power, Pmax, that the DG can afford. It is

Figure 3. Proposed control system of buck-boost converter.

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Figure 4. Flowchart of proposed supervisory control system.

noteworthy that Pmax varies according to the DG type and its operating condition. For

example, the maximum power that can be generated from a PV depends on the weather

conditions. If this action is not enough to avoid further discharging of the ultracapacitor

bank, the supervisory controller commands the diesel generator to increase its active

power, if possible. When the two actions of increasing the generation levels failed to

stop discharging the ultracapacitor bank beyond its minimum limit, the load management

unit is activated. The load management is responsible for load-shedding action, which is

carried out to prevent losing stability of the microgrid. Practically, load shedding is done

in steps starting with the least critical loads until the power balance is retained. This

process continues to keep the ultracapacitor voltage between the allowable minimum

and maximum limits. The proposed supervisory controller may be implemented with the

DESS interface system to access the local measurement of the ultracapacitor voltage and

to transmit the commands to the DG and diesel generator units through a communication

media.

3. The Proposed Frequency Estimation Algorithm

Estimation of microgrid frequency is an important task to get the feedback for the fre-

quency control loop. Speed of convergence, accuracy, noise immunity, structural simplic-

ity, and tracking ability are some of the criteria that a power system frequency estimator

should satisfy. Several methods for tracking and estimating the power line frequency have

been proposed. The PLL is used to estimate the frequency from the measured voltage

signal [19]. The performance of the PLL is deteriorated under distorted and transient

grid conditions. The discrete Fourier transform (DFT) is widely adopted for frequency

estimation due to its inherently superior harmonic rejection [20]. The estimation accuracy

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of the DFT is reduced when the sampling frequency is not synchronized with the analog

signal frequency. To overcome the drawbacks of the DFT, other estimation techniques,

such as extended Kalman filtering [21], least mean square methods [22], Newton type

method [23], and wavelet transform [24], are proposed. However, the convergence speed

and the bulk processing for this group of methods are the main problems for real-time

applications. Moreover, soft computing techniques, such as neural networks [25] and

genetic algorithms [26], are utilized for power system frequency measurement. Although

this approach is suitable for measurement of frequency over a wide range, the on-line

application requires a trade-off between the accuracy and computational complexity. The

research for more accurate, computationally simple, and robust algorithms still continues.

In this article, a simple algorithm based on orthogonal filters is adopted for estimating

the microgrid frequency. Figure 5 presents a block diagram of the proposed frequency

estimation technique. First, the harmonics are removed from the measured voltage signal

v.n/ using a band-pass filter. Two orthogonal finite impulse response (FIR) filters are

utilized to obtain the orthogonal signal components vs.n/ and vc.n/. Each orthogonal

signal component is delayed by k samples and 2k samples using two consecutive delay

units. The microgrid frequency f is calculated from

f D fo

�

1 �1

�

vs.n/vc .n � 2k/ � vc.n/vs.n � 2k/

vs.n/vc .n � k/ � vc.n/vs.n � k/

�

; (2)

where fo is the nominal frequency. Appendix A presents the details of the proposed

frequency estimation algorithm. The proposed algorithm is based on finite differences

rather than derivatives; therefore, neither a high signal sampling rate nor derivatives

correction is required. Furthermore, this algorithm is immune to the frequency response

variations of the filters [27]. A moving average filter is added to remove the oscillation

from the estimated frequency signal. Moreover, two bubble sort modules are employed to

diminish the steady-state error. The bubble sort algorithm works by repeatedly stepping

through the data list to be sorted, comparing each pair of adjacent items, and swapping

them if they are in the wrong order. The pass through the list is repeated until no swaps are

Figure 5. Block diagram of proposed frequency estimation technique.

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needed, which indicates that the list is sorted [28]. The proposed technique for frequency

estimation is characterized by its light computational demand, fast convergence, and

accurate tracking performance.

4. Results and Discussion

The dynamic performance of the proposed systems is evaluated by computer simulation

using the PSCAD/EMTDC software package. The microgrid, shown in Figure 2, is

simulated on the PSCAD/EMTDC software package using the detailed switching models

of the VSI, DC/DC converter, and diesel generator, as verified in the literature [29, 30].

Furthermore, these models of PSCAD/EMTDC are experimentally validated using setups

with similar components to that used in this article [31, 32]. The ultracapacitor model

utilized in this study is based on the equivalent circuit given in [33] with the manufacturer

parameters [34]. The proposed frequency estimation algorithm is programmed by using

FORTRAN in the PSCAD/EMTDC environment. Parameters of the system under study

are given in Appendix B. The upper and lower boundaries of the i�

d limiter for the ultra-

capacitor bank interface are set equal to the positive and negative values of the maximum

continuous current of the ultracapacitor unit. This action allows power exchange between

the ultracapacitor bank and the microgrid in both directions. Since the reverse power flow

to the DG is avoided, the lower boundary of the i�

d limiter for the DG interface is set to

zero. For the HCC switching technique, the hysteresis band is roughly set to 4% of the

maximum value of the VSI current. Different simulation tasks are carried out to examine

the performance of the proposed coordinated control system.

4.1. Case 1: Dynamic Performance of the Proposed Frequency

Estimation Technique

The sampling rate is set at 12 samples per cycle, and delay k is three samples. A

hypothetical AC voltage waveform with different step changes in frequency is used to

assess the dynamic performance of the proposed frequency estimation technique. The

actual and estimated frequencies are depicted in Figure 6. Tight tracking with negligible

steady-state error and fast convergence are evident.

4.2. Case 2: Directly Connected Ultracapacitor Bank

This test case illustrates the operation of the proposed coordinated control system for the

microgrid shown in Figure 2. The ultracapacitor bank consists of 1400 units connected

in series and directly to the DC side of the VSI. The parameters of the ultracapacitor

unit are listed in Table 1. This combination gives a total capacitance of 2.14 F and a total

equivalent series resistance (ESR) of 0.406 ohm. The rated voltage of the ultracapacitor

bank is 3.78 kV.

To examine the dynamic behavior of the proposed coordinated controllers of DG

and DESS, different disturbances are simulated in the microgrid. The first disturbance

is introduced at t D 3 sec, when the active power setting of the diesel generator is

reduced. Second, the load is suddenly increased at t D 5 sec, decreased to its initial

value at t D 7 sec, and further decreased at t D 9 sec. The active power of the load

and the diesel generator are traced in Figures 7(a) and 7(b), respectively. It is obvious

from Figure 7(c) that the proposed DG interface system succeeds to regulate its output

power, PDG, at 40 kW under the different dynamic changes of the microgrid. During the

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Figure 6. Dynamic performance of proposed frequency estimation technique. (color figure avail-

able online)

first second, the DESS interface was disabled to assess the initial status of the microgrid

without the proposed frequency control system. The diesel generator supplies the rest of

the load demand at a reduced frequency, 49.1 Hz, as shown in Figures 7(b) and 7(e),

respectively. It is noteworthy that the frequency is lower than the nominal value due to the

overload condition of the diesel generator. At t D 1 sec, the proposed interface system of

the ultracapacitor bank is enabled. At each disturbance, the DESS interface, which works

as a frequency stabilizer, controls its injected power PDESS, as shown in Figure 7(d), to

keep the power balance and maintain the microgrid frequency at its nominal value of

50 Hz, as indicated in Figure 7(e).

Figure 8 evaluates the dynamic performance of the proposed frequency control

system for the interface of the ultracapacitor bank. The actual and the estimated fre-

quency signals are shown in Figure 8(a), and accurate performance of the proposed

frequency estimation algorithm is revealed. During the different dynamic changes in the

microgrid, there are deviations between the two frequency signals. However, at steady

state, the actual and the estimated frequency signals are fixed at 50 Hz. The direct-axis

reference current component of the proposed interface system of the ultracapacitor bank

i�

d is traced in Figure 8(b). This component is responsible for tightly regulating the

Table 1

Parameters of the ultracapacitor unit [34]

Capacitance 3000 F

Rated voltage 2.7 V

ESR 0.29 mohm

Maximum continuous current 147 A

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Figure 7. Active power of: (a) load, (b) diesel generator, (c) DG interface, (d) DESS interface,

and (e) microgrid frequency.

microgrid frequency at its nominal value. As expected, the shape of the active power

supplied by the DESS interface, shown in Figure 7(d), follows the shape of i�

d .

The reactive power of the load is traced in Figure 9(a). As discussed, the ancillary

service of the DG interface is the voltage regulation at the PCC by compensating the

voltage drops along the feeder. This action leads to negative reactive power of the diesel

generator, as indicated in Figure 9(b). Figure 9(c) illustrates that the DG interface

supplies all the reactive power needed for the microgrid. On the other hand, the DESS

interface does not contribute to reactive power flow (Figure 8(d)), as its quadrature

current component is set to zero. Figure 9(e) shows that the proposed DG interface

system successfully regulates the PCC voltage at 1 p.u. with fast dynamic response even

during the different disturbances in the microgrid. It is obvious from these results that the

control loops of active and reactive power are independent at the two modes of operation,

PV mode and frequency control mode.

Figure 10(a) shows the phase a load current during the increased loading interval. The

diesel generator and the DG interface currents, iDiesel and iDG, are traced in Figure 10(b).

Figure 10(c) illustrates that the PCC voltage vPCC and the DESS interface current iDESS

are in phase. This action is expected, as the quadrature-current command for the DESS

interface is set at zero to achieve maximum power injection per ampere for frequency

stabilization. The total harmonic distortion (THD) of the PCC voltage is less than

1%, while the THDs of the DG and the DESS interface currents, iDG and iDESS, are

below 5%.

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Figure 8. Dynamic performance of the proposed frequency controller for the DESS interface:

(a) actual and estimated frequency and (b) direct-axis current command i�

d.

Figure 11 traces the voltage and the current of the ultracapacitor bank. Initially, the

ultracapacitor is fully charged. The DESS feeds active power to the microgrid during

the period 1 sec � t � 9 sec, as indicated in Figure 7(d), and hence, the ultracapacitor

bank is discharging. It is noteworthy that increasing the injected power from the DESS

increases the ultracapacitor current; consequently, the ultracapacitor voltage drops fast,

as illustrated in Figure 11(a). At t > 9 sec, the microgrid has an excess amount of

power generation. The ultracapacitor bank absorbs this amount of power to regulate the

microgrid frequency. This absorbed power is charging the ultracapacitor bank, hence

raising the DC-link voltage. As expected, the waveforms of the ultracapacitor current

(Figure 11(b)) and the injected power from the DESS interface (Figure 7(d)) have the

same shape.

4.3. Case 3: Ultracapacitor Bank with DC/DC Converter

In this case study, the number of the ultracapacitors is reduced to 467 units from the

same type used in Case 2. This combination yields a total capacitance of 6.424 F, a total

ESR of 0.135 ohm, and a rated voltage of 1.26 kV. The ultracapacitor bank is connected

to the DC link of the DESS interface through the proposed DC/DC converter presented

in Figure 3. The ultracapacitor current is controlled to keep the DC-link voltage, hence

satisfying the power needed to stabilize the microgrid frequency.

The same dynamic changes of the previous case study are applied. The performance

of the different components of the microgrid under study is similar to that shown in

Figures 7 to 10. Figure 12(a) traces the DC-link voltage of the DESS interface system

vDC. The proposed control system of the DC/DC converter succeeds to regulate the

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Figure 9. Reactive power of: (a) load, (b) diesel generator, (c) DG interface, (d) DESS interface,

and (e) PCC voltage.

DC-link voltage at its rated value, 3.78 kV, under different dynamic changes except for

the load increase at t D 5 sec. The voltage and the current of the ultracapacitor bank, vuc

and iuc, are portrayed in Figures 12(b) and 12(c), respectively. The shapes of these traces

are close to the waveforms shown in Figure 11. It is noteworthy that the magnitude of

the ultracapacitor current is almost tripled as the number of units is reduced to one-third

of Case 2.

Initially, the ultracapacitor bank is fully charged. During the period 1 sec � t � 9 sec,

when the DESS feeds power to the microgrid, the ultracapacitor bank is discharging and

the DC/DC converter operates in the boost mode. It is clear that increasing the current

drawn from the ultracapacitor bank increases the discharge rate of ultracapacitor bank.

The sudden load increase at t D 5 sec needs more power, 180 kW, to be injected from the

DESS interface, as indicated in Figure 7(d), to keep the microgrid frequency. Neglecting

the switching losses, the output power from the ultracapacitor bank should approximately

equal to the active power fed from the DESS interface, PDESS. Hence, the required current

of the ultracapacitor bank is calculated as follows:

iuc D PDESS=vuc D 180=1:21 D 148:76 A: (3)

The proposed control of the DC/DC converter limits the ultracapacitor current at its rated

value of 147 A. As a result, the ultracapacitor bank cannot feed the entire amount of

PDESS; consequently, the DC link feeds the rest. Therefore, the DC-link voltage starts

to fall at t D 5 sec. Once the sudden load is switched off at t D 7 sec, the injected

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Figure 10. Waveforms of phase a: (a) load current, (b) diesel generator and DG interface currents,

and (c) PCC voltage and DESS interface current.

Figure 11. Ultracapacitor bank: (a) voltage and (b) current.

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Figure 12. Dynamic performance of proposed DC/DC converter: (a) DC-link voltage, (b) ultra-

capacitor bank voltage, and (c) ultracapacitor current.

power from the DESS is reduced. The DC/DC converter is continuously regulating the

ultracapacitor current at its maximum value to recover the DC-link voltage. At t D

8 sec, the DC/DC converter succeeds to regulate the DC-link voltage at its set value.

Simultaneously, the ultracapacitor current is decreased automatically to the level that

corresponds to the power injected to the microgrid.

The DC/DC converter operates in the buck mode, at t > 9 sec, when the ultraca-

pacitor bank absorbs the excess power from the microgrid through the DESS interface.

It is clear that the proposed control system accurately sets the charging rate of the

ultracapacitor bank, which results in tight regulation of the DC-link voltage. The proposed

DC/DC converter succeeds in regulating the DC-link voltage and in controlling the

ultracapacitor current in both modes of operation.

5. Conclusions

This article presents a coordinated voltage and frequency control of the inverter-based DG

and DESS for the autonomous microgrid. The DG interface is utilized not only to control

the active power flow but also to regulate the voltage of the microgrid. The proposed

interface system of the DESS is controlled to regulate the microgrid frequency and,

hence, stabilize the microgrid. A simple algorithm that is based on orthogonal filters is

adopted for the microgrid frequency estimation. One advantage of the proposed interface

system is that the controller structure remains unchanged for the different operating

modes. An ultracapacitor bank is considered in this article as an energy storage system.

In order to effectively utilize the ultracapacitor bank, a DC/DC converter is used to

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connect the ultracapacitor bank to the DC link of the VSI. The proposed control system

for the DC/DC converter regulates the DC-link voltage of the DESS interface and controls

the ultracapacitor current simultaneously. Different simulation test cases are carried out to

evaluate the behavior of the proposed control systems for various operation modes using

the PSCAD/EMTDC software package. DG and DESS interface systems are successfully

manipulated to achieve voltage and frequency regulation at different disturbances in the

microgrid. A fast response and accurate performance of the proposed control strategies are

revealed from the simulation results. These characteristics render the proposed interface

systems a competitive candidate for autonomous microgrids.

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DATASHEET_K2_SERIES 1015370.pdf

Appendix A

The voltage waveform at the PCC can be modeled as follows:

v.n/ D V cos.n!T C '/; (A1)

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where T is the sampling period; V and ' are the magnitude and phase angle of the voltage

signal, respectively; n is the sample order; and ! is the angular frequency. The measured

voltage v.n/ is treated by two orthogonal FIR filters to yield a pair of orthogonal signals

yc and ys , given by

yc.n/ D

N�1X

iD0

v.n � i/rc.i/ (A2)

and

ys.n/ D

N�1X

iD0

v.n � i/rs.i/; (A3)

where N is the order of the FIR filter, which is equal to the ratio of sampling and power

system nominal frequencies fo and f , respectively. rc and rs are even (cos) and odd

(sin) impulse responses of the FIR filters, respectively. The output of such filters can be

represented by

yc.n/ D FcV cos.n!T C ' C ˛/ (A4)

and

ys.n/ D FsV sin.n!T C ' C ˛/; (A5)

where F and ˛ are the gain and the phase shift angle introduced by the filter. Using

the orthogonal signal components of Eqs. (A2) and (A3), a function gk.!/ is defined as

follows:

gk.!/ D yc.n/ys .n � k/ � ys.n/yc .n � k/: (A6)

With the aid of Eqs. (A4) and (A5), Eq. (A6) is written as

gk.!/ D V 2jFc jjFsj sin.k!T /: (A7)

It is obvious that gk.!/ is proportional to the frequency and magnitude of the measured

signal and the FIR filter gains. To eliminate the dependency on the measured signal

magnitude and the FIR filter gains, a ratio between two versions of Eq. (A7) for different

values of delay, k and 2k, is considered as follows:

g2k.!/

gk.!/D

sin.2k!T /

sin.k!T /D 2 cos k!T: (A8)

Substituting the values of gk.!/ and g2k.!/ from Eq. (A6) into Eq. (A8) gives

cos k!T D1

2

yc.n/ys .n � 2k/ � ys.n/yc .n � 2k/

yc.n/ys.n � k/ � ys.n/yc .n � k/: (A9)

For considerations of convergence speed and sensitivity of frequency estimation, the value

of k is taken equal to N=4. Consequently, the right side of Eq. (A9) is simplified to

cos

�

N

4!T

�

D cos

�

�

2

f

fo

�

D cos

�

�

2

�

1 Cf � fo

fo

��

D � sin

�

�

2

f � fo

fo

�

Š ��

2

f � fo

fo

: (A10)

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Substituting Eq. (A9) into Eq. (A10) gives Eq. (2). Equations (2), (A2), and (A3) with

the required k and 2k delay samples are the key elements of the proposed frequency

estimation algorithm.

Appendix B

The parameters of the system under study are as follows:

Vs (RMS/line) D 11 kV;

fo D 50 Hz;

H D 1 sec;

D D 0:02 p.u.;

nominal power of the diesel generator D 250 kW;

aggregated impedance between the diesel generator and PCC: Ls D 31 mH, Rs D 1:74

ohm;

aggregated impedance between the DG/DESS inverter and PCC: L D 0:9 H, R D 0:12

ohm;

DC-link capacitance: C D 1 mF.

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Documents

A Coordinated Voltage and Frequency Control of Inverter Based Distributed Generation and Distributed Energy Storage System for Autonomous Microgrids