HIERARCHICAL CONTROL SCHEME FOR COMPENSATION OF

VOLTAGE HARMONICS AND UNBALANCE IN ISLANDED

MICROGRID

A Thesis Report Submitted to the Andhra University in partial

Fulfillment of the Requirements for the Award of the Degree of

MASTER OF ENGINEERING

IN

POWER SYSTEMS & AUTOMATION

By

BOLISETTI NAVEEN

(Regd.No:311275727002)

Under the esteemed guidance of

B.MOTHIRAM, M.Tech

Assistant Professor

Department of Electrical & Electronics Engineering

DEPARTMENT OF ELECTRICAL AND ELECTRONICS ENGINEERING

SAGI RAMAKRISHNAM RAJU ENGINEERING

COLLEGE

(AFFILIATED TO ANDHRA UNIVERSITY, VISAKHAPATNAM)(RECOGNISED BY A.I.C.T.E, NEWDELHI)

(Accredited by N.B.A., A.I.C.T.E., NEWDELHI)

BHIMAVARAM-534204, W.G.Dist (A.P)

2011-2013

DECLARATION

This thesis entitled “HIERARCHICAL CONTROL SCHEME FOR

COMPENSATION OF VOLTAGE HARMONICS AND UNBALANCE IN

ISLANDED MICROGRID” has been carried out by me in the partial fulfillment of the

requirements for the award of the degree of M.E (Power systems & Automation), in the

Department of Electrical and Electronics Engineering, S.R.K.R. Engineering College,

affiliated to Andhra University. I hereby declare that this thesis has not been submitted to any

other university/institute for the award of any other degree/diploma.

BOLISETTI NAVEEN

(Regd. No. 311275727002)

ACKNOWLEDGEMENT

Words are inadequate to express the overwhelming sense of gratitude and humble

regards to my supervisor B.Mothiram, Assistant Professor, Department of Electrical and

Electronics Engineering for his constant motivation, support, expert guidance, constant

supervision and constructive suggestion for the submission of my progress report of thesis

work “HIERARCHICAL CONTROL SCHEME FOR COMPENSATION OF VOLTAGE

HARMONICS AND UNBALANCE IN ISLANDED MICROGRID ".

I highly indebted to Principal Dr. D Ranga Raju for the facilities provided to

accomplish this thesis work.

I express my gratitude to Prof. B R K Varma, Head of the Department, for his help

and support during my study. I am thankful for the opportunity to be a member in S.R.K.R

Engineering College of Electrical and Electronics Engineering Department.

I also thank all the teaching and non-teaching staff for their nice cooperation to the

students.

I would like to thank all whose direct and indirect support helped me completing my

thesis in time.

This report would have been impossible if not for the perpetual moral support from

my family members, and my friends. I would like to thank them all.

---BOLISETTI NAVEEN

ABSTRACT

In recent years, distributed generators have proliferated in electrical systems. In this

regard, the concept of microgrid has been newly proposed. A microgrid is a small local grid

which comprises distributed resources and loads and is able to operate in grid-connected and

islanded modes. Distributed generators are often interfaced to the electrical system by power-

electronic converters. The main role of the interface converter is to control power injection.

In this thesis, the control of distributed generators interface converters in order to

improve microgrid power quality is addressed. The proposed control structure is hierarchical

control scheme. In the hierarchical scheme, the power quality enhancement is managed by a

central controller which sends proper control signals to distributed generators. The control

structure consists of primary and secondary levels. The primary control level comprises

distributed generators (DGs) local controllers. Each of these controllers mainly consist of

power, voltage and current controllers, and virtual impedance control loop. The Central

secondary control level is designed to manage the compensation of Sensitive Load Bus

voltage unbalance and harmonics by sending proper control signals to the primary level. Two

cases of islanded microgrid design procedures are discussed in detail and simulated using

Matlab/Simulink software package.

CONTENTS

LIST OF FIGURES v

LIST OF ABBREVIATIONS ix

1. INTRODUCTION

1.1 Overview 1

1.2 Literature Review 1

1.3 Objective of the thesis 2

1.4 Organization of the thesis 3

2. MICROGRIDS: STRUCTURE, OPERATION AND CONTROL

2.1. Introduction 4

2.2. Need for a Microgrid 4

2.3. Microgrid Structure and Components 5

2.3.1. Microsource 6

2.3.2. Power electronic converters 6

2.3.3. Microgrid Load 7

2.3.4. Storage Device 7

2.3.5. Control System 8

2.3.5.1. Microsource controller 8

2.3.5.2. Central Controller 9

2.3.6. Point of Common Coupling 9

2.4. Microgrid Operation 9

2.4.1. Grid Connection 9

2.4.2. Islanded Mode 10

2.4.3. Transition between Grid and Islanded Mode 11

2.5. Hierarchy of Microgrid Controls 11

2.5.1. Primary Control 12

2.5.2. Secondary Control 13

2.5.3. Tertiary Control 14

3. HIERARCHICAL CONTROL STRATEGIES IN MICROGRID

3.1. Introduction 15

3.2. Primary control 15

3.2.1 Active load sharing 17

3.2.2 Droop characteristics techniques 18

3.2.2.1 Frequency droop 20

3.2.2.2 Adaptive droop control 22

3.2.2.3 Virtual frame transformation method 23

3.2.2.4 Virtual impedance loop 25

3.2.2.5 Signal injection method 27

3.2.2.6 Non linear load sharing 29

3.3 Secondary control 31

3.4 Tertiary control 35

4. HIERARCHICAL SCHEME FOR VOLTAGE HARMONICS AND

UNBALANCE COMPENSATION

4.1. Introduction 36

4.2. Primary control level 37

4.2.1. Voltage and current control loop 37

4.2.2. Virtual impedance loop 38

4.2.3. Real-reactive power controller loop 39

4.2.3. Compensation Effort Controller 41

4.3. Secondary control level 43

4.3.1. Voltage Unbalance Compensation 43

4.3.2. Voltage Harmonic Compensation 44

5. SIMULATION RESULTS

5.1. Case-1: Presence of linear unbalanced load 45

5.2. Case-2: Presence of non-linear unbalanced load 51

CONCLUSION 62

REFERENCES 63

APPENDIX 65

AUTHOR’S PUBLICATION 67

LIST OF FIGURES

FIG. No TITLE

PAGE

2.1 Microgrid Structure based on Renewable Energy source 5

2.2 Transition b/w grid connection and islanded mode 11

2.3 Hierarchical control levels in an microgrid 11

2.4 Droop control characteristics 12

2.5 Block Diagram of the Primary and Secondary Control 13

2.6 Block diagram of tertiary control and synchronization loop 14

3.1 PQ control mode with active and reactive power 16

3.2 Reference voltage determination for voltage control mode 16

3.3 Voltage and current control loops in voltage control mode 17

3.4 Conventional droop method 18

3.5 Simplified diagram of a converter connected to the microgird 18

3.6 Frequency deviations with active power sharing 22

3.7 Droop method with virtual power frame transformation. 24

3.8 Block diagram of the virtual output impedance method 24

3.9 Virtual output impedance with voltage unbalance compensator 25

3.10 A typical two-DER system 26

3.11 Block diagram of the signal injection method for reactive power sharing 28

3.12 Block diagram of the updated signal injection method 29

3.13 Control block diagram for the harmonic cancellation technique 30

3.14 hth

harmonic equivalent circuit of a DER 31

3.15 Block Diagram of the Secondary and Tertiary Control 32

3.16 The potential function-based technique block diagram 33

3.17 Voltage unbalance Compensation in the Secondary Control 34

4.1 Block Diagram of Primary Controller 37

4.2 Fundamental virtual impedance loop 38

4.3 Selective Virtual impedance 39

4.4 Block diagram of compensation effort controller 42

4.5 Block diagram of Secondary Control level for unbalance compensation 43

4.6 Block diagram of Secondary Control level for harmonic compensation 44

5.1 Test System of Islanded Microgrid with Unbalanced load 45

5.1.1 Matlab/Simulink Model for Islanded microgrid with linear unbalanced load 46

5.1.2 Voltage Waveform of DG1 (Before compensation) 47

5.1.3 Voltage Waveform of DG2 (Before compensation) 47

5.1.4 Voltage Waveform of PCC (Before compensation) 47

5.1.5 Voltage Waveform of DG1 (After compensation) 48

5.1.6 Voltage Waveform of DG2 (After compensation) 48

5.1.7 Voltage Waveform of PCC (After compensation) 48

5.1.8 Phase-a Negative Sequence Voltage Waveform of PCC, DG1 at 0≤t<2.5 49

5.1.9 Phase-a Negative Sequence Voltage Waveform of PCC, DG1 at 2.5≤t<4.0 49

5.1.1. Voltage Unbalance factor (VUF) of PCC, DG1, DG2 49

5.2 Test System of Islanded Microgrid with Non linear unbalanced load 50

5.2.1 Matlab/Simulink Model for Islanded microgrid with Non linear unbalanced

load

51

5.2.2 Voltage Waveform of Source Bus_1 (SB1) at 𝟎 ≤ 𝒕 < 0.2 52

5.2.3 Voltage Waveform of Source Bus_2 (SB2) at 𝟎 ≤ 𝒕 < 0.2 52

5.2.4 Voltage Waveform of Sensitive Load Bus (SLB) at 𝟎 ≤ 𝒕 < 0.2 52

5.2.5 Harmonic Spectrum Analysis of Sensitive load bus voltage at 𝟎 ≤ 𝒕 < 0.2 53

5.2.6 Fundamental Negative Sequence Current of DG1, DG2 at 0 ≤ 𝑡 < 0.2 53

5.2.7 3rd

Harmonic Sequence Currents of DG1, DG2 at 0 ≤ 𝑡 < 0.2 53

5.2.8 DG1 Output current at 0 ≤ 𝑡 < 0.2 54

5.2.9 DG2 Output current at 0 ≤ 𝑡 < 0.2 54

5.2.10 Voltage Waveform of Source Bus_1 (SB1) at 𝟎. 𝟐 ≤ 𝒕 < 0. 𝟒 55

5.2.11 Voltage Waveform of Source Bus_2 (SB2) at 𝟎. 𝟐 ≤ 𝒕 < 0. 𝟒 55

5.2.12 Voltage Waveform of Sensitive Load Bus (SLB) at 𝟎. 𝟐 ≤ 𝒕 < 0. 𝟒 55

5.2.13 Harmonic Spectrum Analysis of Sensitive load bus voltage at 𝟎. 𝟐 ≤ 𝒕 <

0.4

56

5.2.14 Fundamental Negative Sequence Current of DG1, DG2 at 0.2 ≤ 𝑡 < 0.4 56

5.2.15 3rd

Harmonic Sequence Currents of DG1, DG2 at 0.2 ≤ 𝑡 < 0.4 56

5.2.16 DG1 Output current at 0.2 ≤ 𝑡 < 0.4 57

5.2.17 DG2 Output current at 0.2 ≤ 𝑡 < 0.4 57

5.2.18 Voltage Waveform of Source Bus_1 (SB1) at 𝟎. 𝟒 ≤ 𝒕 < 0. 𝟔 58

5.2.19 Voltage Waveform of Source Bus_2(SB2) at 𝟎. 𝟒 ≤ 𝒕 < 0. 𝟔 58

5.2.20 Voltage Waveform of Sensitive Load Bus (SLB) at 𝟎. 𝟒 ≤ 𝒕 < 0. 𝟔 58

5.2.21 Harmonic Spectrum Analysis of Sensitive load bus voltage at 𝟎. 𝟒 ≤ 𝒕 <

0.6

59

5.2.22 Fundamental Negative Sequence Current at DG1, DG2 at 0.4 ≤ 𝑡 < 0.6 59

5.2.23 3rd

Harmonic Sequence Currents at DG1, DG2 at 0.4 ≤ 𝑡 < 0.6 60

5.2.24 DG1 Output current at 0.4 ≤ 𝑡 < 0.6 60

5.2.25 DG2 Output current at 0.4 ≤ 𝑡 < 0.6 60

5.2.26 Positive sequence real powers of DG1,DG2 61

5.2.27 Positive sequence reactive powers of DG1,DG2 61

CHAPTER 1

INTRODUCTION

1.1 OVERVIEW

The increase in power demand is stressing the transmission and generation system

capabilities, leading to frequent power outages. The central plants are at best 35% efficient

due to transmission and generation losses. The greenhouse gas emissions have risen owing to

the less efficient power system. This led to increased research aiming to meet the growing

energy demand without adding the transmission system capabilities. The use of distributed

generation (wind turbines, CHP plants, PV arrays, etc.,) at the distribution system seems to

be a viable solution. But unplanned application of these new distributed generation

technologies can bring in more problems than solving them. Therefore, a new peer-to-peer

network architecture for distribution system, namely micro-grid was proposed.

A micro-grid has on-site power generation and operates as a single controllable unit

in parallel to the main grid. Micro-grid can enable easy penetration of renewable energy

sources, reduce greenhouse gas emissions, reduce the stress on the grid, lower the energy bill,

create green jobs, and improve the critical reliability and security of the electric grid. It can

also be a part of potential solution for greenhouse gas goals. Micro-grids are almost 85%

efficient as they have very less transmission losses. During power outage or disturbance,

micro-grids can island themselves and retain power availability, avoiding blackouts and lost

productivity. With the power source located on-site, micro-grids are less vulnerable to cyber

attacks on the grid since they do not rely on transmission lines and have the security of

redundant systems. Micro-grids have the ability to address the world’s energy crisis by

reducing the power load on our utility grid; reducing energy security risks and providing

clean energy resources that are more reliable and economical.

1.2 LITERATURE REVIEW

Many control approaches are proposed to control the DG interface converters aiming

to compensate power quality problems. These approaches are designed to enhance voltage

quality at the DG terminal while the power quality at the “Sensitive Load Bus (SLB)” is an

important concern in microgrids.

M. Cirrincione, M. Pucci, and G. Vitale [2] presented a single phase DG which injects

harmonic current to compensate voltage harmonics. However, in the case of sever harmonic

distortion, a large amount of the interface converter capacity is used for compensation and it

may interfere with the power supply by the DG.

T. L. Lee and P. T. Cheng [3] Presented a method for compensation of voltage harmonics in

an islanded microgrid. This method is also based on the resistance emulation and applies a

harmonic power droop characteristic in order to share the compensation effort among DGs.

P. T. Cheng, C. Chen, T. L. Lee, and S. Y. Kuo [4] presented on controlling each DG unit

of a microgrid as a negative sequence conductance to compensate voltage unbalance. The

conductance reference is determined by applying a droop characteristic which uses negative

sequence reactive power to provide the compensation effort sharing.

Y. Li, D. M. Vilathgamuwa, and P. C. Loh,[5] presented a control method based on using

a two inverter interface converter (one connected in shunt and other in series with the grid) in

order to control power flow and also to compensate the voltage unbalance. This two-inverter

structure can be unattractive considering the cost and volume of the DG interface converter.

1.3 OBJECTIVE OF THE THESIS

Due to the ever-increasing demand for high-quality and reliable electric power, the

concept of distributed energy resources has attracted widespread attention in recent years.

Distributed energy resources consist of relatively small-scale generation and energy storage

devices that are interfaced with low- or medium-voltage distribution networks and can offset

the local power consumption, or even export power to the upstream network if their

generation surpasses the local consumption. An upcoming philosophy of operation which is

expected to enhance the utilization of distributed energy resources is known as the microgrid

concept. A microgrid is referred to as a part of a distribution network embedding multiple

distributed energy resources and regional loads, which can be disconnected from the

upstream network under emergency conditions or as planned. The main benefits of

microgrids are high energy efficiency through the application of Combined Heat and Power

(CHP), high quality and reliability of the delivered electric energy, and environmental and

economical benefits.

The issue of the power quality in microgrids is an important issue due to the presence

of an appreciable number of sensitive loads whose performance and life span can be

adversely affected by voltage harmonics, and imbalances. In a microgrid, however, most

distributed energy resources employ power-electronic converters which can rapidly correct

voltage imbalances and harmonics, etc., even in the presence of nonlinear and/or unbalanced

loads. In addition, the proximity between generation and consumption can improve the

reliability of service to sensitive loads. Reliability is further enhanced by diversification and

decentralization of the supply; thus, loss of one unit can be compensated for by the other

units. It should be noted that the distributed energy resources of a microgrid must have plug-

and-play capabilities such that they can be connected to the microgrid with zero or minimum

on-site engineering.

1.4 ORGANIZATION OF THE THESIS

Chapter 1: includes the introduction , literature survey and brief analysis of thesis

work.

Chapter 2: explains about microgrid structure, operation and control levels

Chapter 3: includes the explanation of hierarchical control strategies in microgrid

Chapter 4: discusses the hierarchical control scheme of microgrid for compensating

voltage harmonics and unbalance

Chapter 5: explain all the simulation results and analysis of thesis.

The parameters used for simulation are given in Appendix.

CHAPTER 2

MICROGRIDS: STRUCTURE, OPERATION AND CONTROL

2.1 INTRODUCTION

A microgrid is a network consisting of distributed generator and storage devices used

to supply loads. A distributed generator (DG) in a microgrid is usually a renewable source,

such as combined heat and power (CHP), photovoltaic (PV), wind turbine, or small-scale

diesel generator. DGs are usually located near the loads, so that line losses in a microgrid are

relatively low. A microgrid can work with a host grid connection or in islanded mode. When

grid connected, DGs supports the main grid during peak demand. However, if there is a

disturbance in the main grid, a microgrid can supply the load without the support of the main

grid. Moreover, a microgrid can be reconnected when the fault in the main grid is removed.

Furthermore, as in any technology, microgrid technology faces many challenges. Many

considerations should be taken into account, such as the control strategies based on of the

voltage, current, frequency, power, and network protection.

2.2 NEED FOR A MICROGRID

A microgrid is used for many reasons. It is a new paradigm that can meet the increase in

the world’s electrical demand. It can also increase energy efficiency and reduce carbon

emission, because the DGs commonly use renewable sources or a small-scale back-up diesel

generator. By using a microgrid, the critical loads will be ensured to be supplied all the time.

Economically, extending the main grid is expensive, so a microgrid can be used to supply the

load instead. Moreover, the main grid is supported by DGs; therefore, overall power quality

and reliability will improve. Also, by using a microgrid, the main grid generators will supply

less power. Having a generator of the main grid that runs with less fossil fuels is beneficial.

Another economic reason is that the DGs are located near the load, and thus line losses are

kept to a minimum. A microgrid can be used to supply energy to remote areas or in places

where the host grid is both inefficient and difficult to install. For example, in some areas, the

load demand is so low that the load can be supplied entirely by small-scale DGs. Therefore, a

microgrid is the suitable choice for supplying the load demand. Moreover, some areas have

harsh geographic features, making the main grid difficult to connect. Using a microgrid is the

best solution to provide power to these areas. In summary, the most important issues that

make the microgrid technology important are:

Load demand has increased worldwide.

Microgrids use renewable sources, so they have less impact on the environment.

Extending the main grid is not only costly but also difficult.

A microgrid can supply critical loads even if it is disconnected from the main grid.

2.3 MICROGRID STRUCTURE AND COMPONENTS

Figure 2.1. shows the structure of a microgrid. The main grid is connected to the

microgrid at the point of a common coupling. Each microgrid has a different structure

(number of the DGs and types of DGs), depending on the load demand. A microgrid is

designed to be able to supply its critical load. Therefore, DGs should insure to be enough to

supply the load as if the main grid is disconnected. The microgrid consists of microsources,

power electronic converters, distributied storage devices, local loads, and the point of

common coupling (PCC). The grid voltage is reduced by using either a transformer or an

electronic converter to a medium voltage that is similar to the voltage produced from the DG.

The components of the microgrid are as follows.

Figure.2.1. Microgrid Structure based on renewable energy sources

2.3.1 MICROSOURCE

A microsource is a small-scale energy source located near a load. It can be either a

dispatchable or a non-dispatchable energy source in a microgrid network. The difference

between the dispatchable and non- dispatchable unit is that the dispatchable unit is

considered a voltage source because the amount of voltage output can be controlled. In

contrast, the non- dispatchable unit is considered a current source, in which the output

voltage level cannot be controlled. An example of a non- dispatchable unit is the PV panel.

PV ceases to produce energy if there is no sun. However, in a voltage source, the voltage

amount can be controlled (i.e., turned on/off) or increased/decreased depending on the

voltage required for the microgrid load. The voltage from generators can be controlled by

controlling the speed of the generators. Microsources are usually small scale, less than 50

MW. They can be present as renewable source in the device in the form of CHP, solar PV,

wind turbine, or fuel cell. Furthermore, the voltage of microsources can be DC or AC,

depending on the type of the microsource. For example, PV produces DC voltage, whereas

wind produces AC voltage. Therefore, microsources are usually connected to a power

electronics converter. One of the advantages of microsources is that line losses are reduced as

microsources can be located near the load. In sum, a microsource is part of a microgrid. It

can be a dispatchable or a non-dispatchable unit that can a produce DC or AC voltage. It is

usually connected to inverters and is located close to the load.

2.3.2 POWER ELECTRONICS CONVERTERS

A power electronics converter is a device that is used to regulate and control the DG

voltage and frequency. It can operate with power ranging from MW to GW. In a microgrid,

power electronic converters are connected to the DGs to convert the voltage output from the

DG from one form to another, depending on the type of voltage produced by the DG. For

example, if the DG is a PV panel, the voltage produced is in DC form. Therefore, the voltage

should be converted from DC to AC to match the voltage type of the microgrid load. Another

example is that the voltage produced by wind turbine is AC, but it is not in the desired

magnitude and phase. Thus, the voltage should be converted from AC to DC and from DC to

AC with acceptable magnitude and phase. The terms inverter and converter should not be

used interchangeably. The inverter changes the DC voltage to AC voltage, whereas the

converter changes the magnitude of the AC voltage. Converters can step up or step down the

voltage produced by DGs. The power electronics converter also serves as a control device

that can be used to control the voltage and frequency of DGs. Therefore, the amount of the

voltage and frequency can be produced at a certain value by adjusting the converter.

2.3.3 MICROGRID LOAD

The load of the microgrid can be houses, hospitals, banks and malls. This loads can

be classified into two types. The first type is called critical load, examples of which are a

hospital or a bank’s computer system. As indicated by the examples, critical load should be

supplied with an uninterruptible energy source that has high power quality. The second type

is called uncritical load, examples of which are park lights or air conditioners or streetlights.

Uncritical loads can be disconnected when there is a shortage of power supply or if the main

grid is disconnected. Uncritical loads are usually supplied by a current source, such as PV, or

storage devices. Disconnecting the uncritical load is used in many microgrid applications

when operating in islanded mode. The loads of a microgrid are usually supplied by both the

grid and the microgrid. However, if the grid is disconnected, two issues arise related to

microgrid load. The critical load should be ensured to have enough energy from the

microsource, and the uncritical load may be disconnected. After the main grid is reconnected

(after the disturbance has been removed), the uncritical load can be supplied by both the grid

and microgrid, depending on the microgrid operation policy.

2.3.4 STORAGE DEVICES

Storage energy devices store energy when there is excess energy. However, they

work as generators when there is a power shortage in the network. Thus, they work as back-

up energy sources. Storage energy devices are commonly used when renewable energy

sources are used in the microgrid, as some applications of renewable energy devices can stop

producing energy in some circumstances ( for example, wind turbines require wind to

produce electrical power). Furthermore, storage energy devices come in different types, such

as battery, flywheel, and ultra capacitor. Each type of energy storage device is different from

each other in its properties and its type of voltage output. For example, a battery produces a

DC voltage, whereas a flywheel produces an AC voltage. The time response is different from

one type of storage device to another. For example, the response of a flywheel is faster than

that of a battery. Therefore, including storage devices in the microgrid depends on how

important the storage devices are to the microgrid. Some microgrids are designed to have

storage devices that serve as a very important component in the microgrid. Another

microgrids, may be is designed to disconnect uncritical load instead. In some applications,

the storage devices are included in the microgrid if the load of the microgrid will increase in

future. The disadvantages of the storage device are that storage energy devices are expensive,

and they can only sometimes buck-up for short period of time (such as seconds or minutes,

but not hours).

2.3.5 CONTROL SYSTEM

The control system is an important component of the microgrid operation because it

ensures that the system works correctly. For example, if it is working optimally, the carbon

emission will be reduced as generators will run with less fossil fuels. Moreover, the transfer

from one mode to other is conducted safely. A microgrid commonly requires a microsource

controller (MC) and a central controller (CC). Each type of control system is discussed in the

following subsections .

2.3.5.1 MICROSOURCE CONTROLLER (MC)

Using the MC is considered the first step in microgrid control. The MC has the

benefit of using the power electronics devices built into the DG sources. It uses local

information about the microgrid status and functions depending on the microgrid status. The

MC controls the voltage and frequency of the microgrid. This control enables the DGs to

maintain their power output if the load changes or switches to the islanded mode or reconnect

to the main grid. Therefore, DGs respond according to the system changes. One of the

advantages of the MC is that it responds quickly to any disturbance or load change.

Moreover, using this type of controller does not require communication between the DGs.

The MC control strategy uses the P-F and Q-V control methods, which are the droop control

methods. The MC usually acts as the primary control, which will be discussed in detail later.

2.3.5.2 CENTRAL CONTROLLER (CC)

The CC is used in the microgrid to ensure its safe overall operation control. It requires

communication between the DGs. It is used to reset the voltage and frequency set points for

the entire MC. The new set points of the voltage and frequency are sent from the CC to the

MCs to ensure that the operation of the microgrid is performed optimally. Moreover, the CC

is used to update the set points of the voltage and frequency when the host grid is

disconnected from the microgrid. It updates the new set points when the main grid is

reconnected to the microgrid after the disturbance is removed. The CC acts as a secondary

controller respond more slowly than the MCs. The key functions of the CC are

to provide the individual power and voltage set points for each DG controller,

to minimize emissions and system losses,

to maximize the operational efficiency of the microsources, and

to provide logic and control for islanding and reconnecting the MG during events.

2.3.6 POINT OF COMMON COUPLING PCC

The PCC acts as a switch between the main grid and the microgrid. This component

is important for the microgrid because it protects the microgrid from the main grid during a

disturbance on the main grid. If there is a fault in the main grid, the switch opens to isolate

the microgrid from the main grid. When the fault is cleared, the switch closes to reconnect

the microgrid to the main grid. The PCC isolates the main grid from the microgrid if the main

grid experiences disturbances, such as poor voltage quality, voltage sag, voltage or frequency

of the main grid not being within the acceptable limits, and increases in current due to a fault.

2.4 MICROGRID OPERATION

A microgrid being a plug and play power unit does have different operational modes.

More specifically, a microgrid that is an integral part of a bulk grid system can only have the

following modes of operation:

2.4.1 GRID CONNECTION MODE

The grid connection mode is the normal operation status of the microgrid. In this

mode, the load is supplied by both the grid and the microgrid. The voltage of the grid is

determined by the PCC. The voltage of the grid should be in the same phase as the voltage

generated by the DG. Therefore, in the grid connection mode, the voltage and frequency of

the DG are controlled by the grid voltage and frequency.

2.4.2 ISLANDED MODE

When the grid experiences a fault or disturbance, the main grid is disconnected from

the microgrid by the PCC switch. In this situation, the microgrid loads are supplied only by

the DGs. Thus, the voltage amplitude and frequency are regulated by the DGs, and the DGs

are responsible for the stability of the system by providing nominal voltage and frequency for

the microgrid. In islanded mode, three important aspects should be dealt with care.

First, the voltage and frequency must operate within the acceptable limits.

Voltage and frequency management: The primary purpose is to balance the system against

losses and system disturbances so that the desired frequency and power interchange is

maintained. that is why, voltage and frequency inner loops must be adjusted and regulated as

reference within acceptable limits

Second, there must be a balance between the supply and demand, as the frequency will

change at the islanded mode, which in turn will change the supply of real power.

Supply and demand balancing: when the system is importing from the grid before islanding,

the resulting frequency is smaller than the main frequency, been possible that one of the units

reaches maximum power in autonomous operation. Besides, the droop characteristic slope

tries to switch in vertical as soon as the maximum power limit has been reached and the

operating point moves downward vertically as load increases. In the opposite case, when the

unit is exporting and the new frequency is larger than nominal.

Third, DGs should provide excellent power quality.

Power quality: power quality must synthesize quality of supply and quality of consumption

using sustainable development as transporting of renewable energy, embedded generation,

using high requirements on quality and reliability by industrial, commercial and domestic

loads/costumers avoiding variations as harmonic distortion or sudden events as interruptions

or even voltage dips.

After the primary control is applied in islanded mode, a small deviation in the voltage and

frequency can be observed in the microgrid. This deviation must be removed to ensure the

full and stable operation of the microgrid in islanded mode.

2.4.3 TRANSITION BETWEEN GRID CONNECTION AND ISLANDED MODE

The third type of operation mode of a microgrid is the transition between grid

connection and islanded mode. The transition operation of a microgrid is the time between

the microgrid disconnection from the grid and the reconnection to the grid. In this situation,

the voltage amplitude and frequency should be controlled to be within the acceptable limits

to ensure the safe transition from one mode to another. At this stage, the static switch adjusts

the power reference to the desired value. The voltage and frequency can be measured inside

the microgrid. The maximum value allowed for the change in voltage and frequency is 2%

for frequency and 5% of the voltage amplitude.

Figure.2.2. Transition between grid connection and islanded mode.

2.5. HIERARCHY OF MICROGRID CONTROLS

Microgrids have three levels of control: primary control, secondary control, and

tertiary control. Microgrids should operate with these controls to ensure stable operation.

This section expounds on the primary and secondary controls for islanded mode only.

Figure.2.3 Hierarchical Control levels in an Microgrid

2.5.1 PRIMARY CONTROL

Primary control is considered the first level of the microgrid control. This control

strategy is implemented in each DG. This strategy is conducted using the P/Q control

method. In the P/Q control strategy, real power is controlled by the frequency, and reactive

power is controlled by the voltage. This strategy is expressed in the following equations:

𝑃 = (𝐸−𝑉 )sin 𝜃

𝑋 (2.1)

𝑄 = (𝐸−𝑉) cos 𝜃−𝑉2

𝑋 (2.2)

The droop method is used for primary control and for controlling the microsources

themselves. Moreover, as previously mentioned, this type of control does not require

intersource communication. The main aim of primary control is to control the voltage and

frequency of the microsources. It ensures that each DG generates within the acceptable limit

of the voltage and frequency by controlling the real and reactive power of the microsources.

Figure.2.4 Droop Control Characteristics

As shown in Figure 2.4, when the frequency increases, real power decreases, and vice

versa. Moreover, when the voltage increases, reactive power decreases, and vice versa. When

islanded mode occurs, both frequency and voltage immediately decrease. Hence, the

microsource should be adjusted to deliver enough real and reactive power to the critical

loads. The following equation introduces the control equation for the droop method:

𝜔 = 𝜔∗ + 𝑚(𝑃 − 𝑃∗) (2.3)

𝐸 = 𝐸∗ − 𝑛(𝑄 − 𝑄∗) (2.4)

where ω and E are the amplitude frequency and voltage output, respectively, and ω*, E*, P*,

and Q* are the frequency, voltage, real power, and reactive power references, respectively. m

and n are the slopes of the equations. The reference of the real and reactive power is usually

set to zero. The voltage magnitude and frequency delivered by DGs can be adjusted using

these equations.

2.5.2 SECONDARY CONTROL

The secondary control is the second level of the hierarchy of microgrid controls. Its

main aims are to provide high power quality to the microgrid and to reduce the long-term

voltage and frequency deviations. As the primary control produces a voltage and frequency

deviation, this deviation should be removed or reduced to ensure the stable operation of the

microgrid. This deviation can be removed by readjusting the set points of the microgrid

voltage and frequency. Thus, the secondary control ensures the safe operation of the

microgrid by providing appropriate set points according to the microgrid status. The

secondary control can be carried out by building a controller that compares the set point with

the point produced by the DG. After the comparison, the controller sends the nominal value

back to the DG to make sure that voltage and frequency produced have nominal values.

Moreover, note that the secondary control is carried out after the primary control reaches its

steady state. Otherwise, a coupling between the primary and secondary controls occurs.

Figure.2.5 Block diagram of the primary and secondary control

2.5.3 TERTIARY CONTROL

In the third control hierarchy, the adjustment of the inverters references connected to

the Microgrid and even of the generators maximum power point trackers is performed, so

that the energy flows are optimized. The set points of the Microgrid inverters can be

adjusted, in order to control the power flow, in global (the Microgrid imports/exports energy)

or local terms (hierarchy of spending energy). Normally, power flow depends on economic

issues. Economic data must be processed and used to make decisions in the Microgrid. Each

controller must respond autonomously to the system changes without requiring load data, the

IBS or other sources. Thus, the controller uses a power and voltage feedback control based on

the real-time measured values of both P, Q, frequency and ac voltage to generate the desired

voltage amplitude and phase angle by means of the droop control.

Figure.2.6 Block diagram of the Tertiary control and Synchronization loop

CHAPTER 3

HIERARCHICAL CONTROL STRATEGIES IN MICROGRID

3.1 INTRODUCTION

Conventional electric power systems are facing continuous and rapid changes to

alleviate environmental concerns, address governmental incentives, and respond to the

consumer demands. The notion of the smart grid has recently emerged to introduce an

intelligent electric network. Improved reliability and sustainability are among desired

characteristics of smart grid affecting the distribution level. These attributes are mainly

realized through microgrids which facilitate the effective integration of Distributed Energy

Resources (DER). Microgrids can operate in both grid-connected and islanded operating

modes. Proper control of microgrid is a prerequisite for stable and economically efficient

operation. The principal roles of the microgrid control structure are:

• Voltage and frequency regulation for both operating modes;

• Proper load sharing and DER coordination;

• Microgrid resynchronization with the main grid;

• Power flow control between the microgrid and the main grid;

• Optimizing the microgrid operating cost.

These requirements are different significances and time scales, thus requiring a

hierarchical control structure to address each requirement at a different control hierarchy.

3.2 PRIMARY CONTROL

The primary control is designed to satisfy the following requirements

• To stabilize the voltage and frequency. Subsequent to an islanding event, the microgrid may

lose its voltage and frequency stability due to the mismatch between the power generated and

consumed.

• To offer plug and play capability for DERs and properly share the active and reactive

power among them, preferably, without any communication links.

• To mitigate circulating currents that can cause over-current phenomenon in the power

electronic devices and damage the DC-link capacitor.

The primary control provides the reference points for the voltage and current control

loops of DERs. These inner control loops are commonly referred to as zero-level control. The

zero level control is generally implemented in either PQ or voltage control modes

Figure.3.1. PQ control mode with active and reactive power

In the PQ control mode, the DER active and reactive power delivery is regulated on

the pre-determined reference points, as shown in Fig.3.1. The control strategy is implemented

with a current- controlled voltage source converter (VSC). In Fig.3.1, 𝐻1controller regulates

the DC-link voltage and the active power through adjusting the magnitude of the output

active current of the converter 𝑖𝑝 . 𝐻2 controller regulates the output reactive power by

adjusting the magnitude of the output reactive current, i.e,.𝑖𝑞

Figure.3.2. Reference voltage determination for voltage control mode

In the voltage control mode, the DER operates as a voltage controlled VSC where the

reference voltage, 𝑣0∗ , is determined by the primary control, conventionally via droop

characteristics as shown in Fig. 3.2. The nested voltage and frequency control loops in the

voltage control mode are shown in Fig. 3.3. This controller feeds the current signal as a

feedforward term via a transfer function (e.g., virtual impedance). To fine-tune the transient

response, proportional-integral-derivative (PID), adaptive, and proportional resonant

controllers are proposed for the voltage controller.

Figure.3.3. Voltage and current control loops in voltage control mode

Power quality of small-scale islanded systems is of particular importance due to the

presence of nonlinear and single-phase loads and the low inertia of the microgrid. To

improve the power quality for a set of energy sources connected to a common bus, the

control structure shown in Fig. 3.4 is used. In this figure, 𝐻𝐿𝑃𝐹 (𝑆) denotes the transfer

function of a low-pass filter. Each converter has an independent current control loop, and a

central voltage control loop that is adopted to distribute the fundamental component of the

active and reactive powers among different sources. The reference point for the voltage

control loop is determined by the primary control. The individual current controllers ensure

power quality by controlling the harmonic contents of the supplied currents to the common

AC bus

The DER’s control modes are usually implemented using the active load sharing and droop

characteristic techniques

3.2.1 ACTIVE LOAD SHARING

The active load sharing is a communication-based method used in parallel

configuration of converters. Current or active/ reactive power reference point is determined

through different approaches such as centralized, master-slave, average load sharing and

circular chain control methods. In a centralized control method, the overall load current is

evenly distributed among the sources by assigning the same current set points for all

converters. In the master-slave control, the master converter operates as a VSC and regulates

the output voltage while the slave converters behave as individual current source converters

that follow the current pattern of the master converter. In the average load sharing control,

the current reference for individual converters is continuously updated as the weighted

average current of all converters (but not the load current). In the circular chain control,

converter modules are considered to be connected like links of a chain, and the current

reference for each converter is determined by that of the previous converter. The active load

sharing method requires communication links and high bandwidth control loops. However, it

offers precise current sharing and high power quality.

Figure.3.4. Conventional droop method.

3.2.2. DROOP CHARACTERISTIC TECHNIQUES

The droop control method has been referred to as the independent, autonomous, and

wireless control due to elimination of intercommunication links between the converters. The

conventional active power control (frequency droop characteristic) and reactive power

control (voltage droop characteristic), those illustrated in Fig. 3.4, are used for voltage mode

control.

Figure.3.5. Simplified diagram of a converter connected to the microgird

Principles of the conventional droop methods can be explained by considering an

equivalent circuit of a VSC connected to an AC bus, as shown in Fig. 3.5. If switching

ripples and high frequency harmonics are neglected, the VSC can be modeled as an AC

source, with the voltage of 𝐸∠δ. In addition, assume that the common AC bus voltage

𝑉𝑐𝑜𝑚 ∠0 is and the converter output impedance and the line impedance are lumped as a single

effective line impedance of 𝑍∠θ. The complex power delivered to the common AC bus is

calculated as

S = P + jQ = VI∗ (3.1)

Where,

𝐼∗ = ((𝐸 − 𝑉 ) 𝑍 ) ∗ (3.2)

Putting (2) in (1),

𝑆 =𝐸 𝑉𝑒 (𝜃−𝛿)

𝑍−

𝑉2𝑒 𝑗𝜃

𝑍 (3.3)

Applying Euler’s formula on equation (3.3) and equating it to (3.1), results in the following

equations for active and reactive power:

𝑃 =𝐸 𝑉 cos (𝜃−𝛿)

𝑍−

𝑉2𝑐𝑜𝑠𝜃

𝑍 (3.4)

𝑄 =𝐸 𝑉 sin (𝜃−𝛿)

𝑍−

𝑉2 sin 𝜃

𝑍 (3.5)

Where Z=R+jX and 𝜃 = 90°. Considering small line length the phase angle separation

𝛿 is taken as a small value. Hence, sin𝛿 = 𝛿 and cos𝛿= 1. With X>>R, (3.4) and (3.5) can be

written as

𝑃 =𝐸 𝑉 sin δ

X~

𝐸𝑉𝛿

X (3.6)

𝑃 =𝐸 𝑉 cos δ

𝑋−

𝑉2

𝑋~

𝐸𝑉

𝑋−

𝑉2

𝑋 (3.7)

Therefore, from (3.6) and (3.7) it can be concluded that active power (P) can be

varied by changing the angle 𝛿and the reactive power can be controlled by changing the

voltage E. This results in the decoupling of the active and reactive power and hence they can

be controlled separately. In an islanded microgrid due to the lack of communication channel

each of the DGs are not aware of the phase angle information of other DGs. Therefore,

frequency droop is used as the conventional method for load sharing.

3.2.2.1Frequency droop:

As frequency ω can be represented as change of the angle (d𝛿/dt), the active power

(P) can be controlled by controlling the frequency ω and the reactive power (Q) by varying

the voltage (E) as per (3.6) and (3.7) Therefore the conventional frequency voltage droop

characteristics can be expressed as:

𝜔 = 𝜔0 − 𝑚𝑃 (3.8)

𝐸 = 𝐸0 − 𝑛𝑄 (3.9)

where P and Q are the average values calculated from instantaneous active and

reactive power. ω0 and E0 are the rated frequency and voltage output of the DG unit, with m

and n as the frequency droop co-efficient and voltage droop co-efficient respectively.

The average active and reactive powers are calculated by deploying a low pass filter

(LPF). The LPF with a reduced bandwidth results in a slow dynamic response of the system.

Also, the droop control is limited by the maximum allowed limit of the deviation of the

frequency (2%) and the voltage (5%). Therefore, the conventional droop method is modified

in order to improve the dynamic response and also to maintain the frequency within its safe

limits. In case of reactive power, the average value is obtained by delaying the output current

and voltage by 90° before passing through the LPF. PD control is applied over the output of

the LPF, which improves the dynamics of the system . The modified voltage amplitude can

be expressed as:

𝐸 = 𝐸0 − 𝑛𝑄 − 𝑛𝑑𝑑𝑄

𝑑𝑡 (3.10)

In case of the active power, the phase angle (∅= 𝑑𝑤

𝑑𝑡 ) is adjusted by implementing a

PID controller on the output of the LPF. The modified expression can be rewritten as:

∅ = − 𝑃𝑑𝜏𝑡

−∞− 𝑚𝑝𝑃 − 𝑚𝑑

𝑑𝑝

𝑑𝑡 (3.11)

In both the equation (3.10) and (3.11) m and n are used to fix the steady state droop

characteristics, whereas nd (derivative coefficient for reactive power), mp and md

(proportional and derivative coefficients respectively for active power) takes care of the

stability and the transient response of the system. Control of the steady state frequency

deviation can also be achieved by only applying a PD control action on the non-dc

component of the active power 𝑝 , which is obtained by passing the average active power

(obtained using LPF) through a high pass filter (HPF). As per the modified frequency droop

can be expressed as:

𝜔 = 𝜔𝑚𝑎𝑥 − 𝑚𝑝𝑝 − 𝑚𝑑𝑑𝑝

𝑑𝑡 (3.12)

This method can guarantee the steady state frequency regulation along with power balance at

load transients.

Now, considering a system having multiple DGs , the conventional equation in (3.8) is

equated in order to establish a condition of constant frequency throughout the system:

𝜔0 − 𝑚𝑖𝑝𝑖 = 𝜔0 − 𝑚𝑗 𝑝𝑗 (3.13)

where, i and j represents the ith and jth DG unit.

The slope m is increased to m’ = m+Δm, which will lead to the increase of Δ𝜔 or decrease of

P. This can be further explained by Figure

Figure 3.6 Frequency deviations with active power sharing

In Figure 3.6 mi,j>mi,j which results in Δp< Δp’ Therefore it can be concluded that on

increasing the droop coefficients increases the accuracy of load sharing, i.e. the difference in

the power shared (Δp) by the DGs decreases (similarly for voltage droop). But it comes at the

cost of increase in the frequency (Δw< Δw’ ), which makes it difficult to keep the frequency

within its allowed limits; hence it results in system instability.

3.2.2.2 Adaptive Droop Control:

In this approach an Adaptive droop control has been implemented, which is capable

of changing the gain value with the change in load demand and the DG supply. This control

action is based on equation (3.17), which deals with the change in power supplied by the DG

and the change in load demand, with the objective to keep the system frequency (ω) within

its safe limit. Therefore, a high value of droop coefficient is selected when the power

supplied by DG goes below the rated power (P0), whereas a low droop gain results in faster

steady state where the load power demand is high. This method uses a threshold active

(Pithres) and reactive power (Qithres), which are load dependent, in order to compare with the

active (Pi) and reactive (Qi) power outputs of the ith DG unit to set the value of the droop

coefficient. The logic can be stated as follows:

When Pi<P(ithres) ,mi<mi0

And Pi>P(ithres) ,mi<mi1

Similarly,

When Qi<Q(ithres) ,ni<ni0

And Qi>Q(ithres) ,ni<ni1

This method damps oscillations and helps to reach steady state faster. However, this method

degrades the accuracy of load sharing among the DGs.

Line characteristics: The droop characteristics discussed above greatly depends upon on the

network characteristics and the load type. The conventional droop equations (3.8)-(3.9) are

derived based on the equations (3.6) and (3.7), which assumed the network to be highly

inductive i.e. a high X/R ratio. Now, considering resistive impedance (low X/R), Z in the

(3.4) and (3.5) is replaced by R and 𝜃 with zero. Therefore the modified (3.4) & (3.5) can be

written as:

𝑃 =𝐸 𝑉 co s∅

𝑅−

𝑉2

𝑅~

𝐸𝑉

𝑅−

𝑉2

𝑅 (3.14)

𝑄 =𝐸 𝑉 sin ∅

𝑅~

𝐸𝑉∅

𝑅 (3.15)

Similar to (3.4) and (3.5): sin∅ = ∅ and cos∅ = 1 for small value of ∅. Therefore the droop

equations of (3.8) and (3.9) can be modified as

𝜔 = 𝜔0 + 𝑚𝑄 (3.16)

𝐸 = 𝐸0 − 𝑛𝑃 (3.17)

In a fully resistive microgrid it is not possible to decouple the active and reactive

powers and hence making it difficult to implement a control strategy as both the active and

reactive powers are affected by a change in frequency/phase angle or voltage. However,

while applying the conventional droop method the output impedance of the inverters (also

the line impedance) was considered predominantly inductive. But, the inverter output

impedance also depends upon the control strategy implemented and its system parameters.

This results in a mismatch of the output inductance of the different DGs used. This mismatch

can result in the following two consequences:

(i) Error in reactive power sharing.

(ii) Circulating current due to the difference in voltages

In a low voltage microgrid, having resistive line impedance, virtual inductance (Lv1, Lv2)

can be used in order to decouple the active power from the reactive power.

3.2.2.3.Virtual Frame Transformation Method:

An orthogonal linear transformation matrix,𝑇𝑃𝑄 , is used to transfer the active/ reactive

powers to a new reference frame where the powers are independent of the effective line

impedance . For the system shown in Fig. 3.7, 𝑇𝑃𝑄 is defined as

𝑃1

𝑄1 = 𝑇𝑃𝑄 𝑃𝑄 =

𝑠𝑖𝑛𝜃 −𝑐𝑜𝑠𝜃𝑐𝑜𝑠𝜃 𝑠𝑖𝑛𝜃

𝑃𝑄 (3.18)

The transformed active and reactive powers, and 𝑃1 , 𝑄1 are then used in droop

characteristics in (4). The block diagram of this technique is shown in Fig. 3.7

Similarly, a virtual frequency/voltage frame transformation is defined as

𝜔1

𝐸1 = 𝑇𝜔𝐸 𝜔𝐸 =

𝑠𝑖𝑛𝜃 𝑐𝑜𝑠𝜃−𝑐𝑜𝑠𝜃 𝑠𝑖𝑛𝜃

𝜔𝐸 (3.19)

Where 𝐸 and 𝜔 are calculated through the conventional droop equations in (4). The

transformed voltage and frequency, 𝐸1and 𝜔1 , are then used as reference values for the

VSC voltage control loop

Figure.3.7. Droop method with virtual power frame transformation.

The virtual frame transformation method decouples the active and reactive power

controls. However, the applied transformation requires a prior knowledge of the effective line

impedance. Moreover, the control method does not consider possible negative impacts of

nonlinear loads, does not ensure a regulated voltage, and comprises a basic tradeoff between

the control loop time constant adjustment and voltage/frequency regulation.

Figure.3.8. Block diagram of the virtual output impedance method

3.2.2.4.Virtual Output Impedance:

An intermediate control loop can be adopted to adjust the output impedance of the

VSCs. In this control loop, as depicted in Fig. 3.8, the VSC output voltage reference, 𝑣𝑟𝑒𝑓 , is

proportionally drooped with respect to the output current, 𝑖0, i.e.,

𝑣𝑟𝑒𝑓 = 𝑣0∗ − 𝑍𝑉(𝑆)𝑖0 (3.20)

Where 𝑍𝑉(𝑆) is the virtual output impedance, and 𝑣0∗ is the output voltage reference

that is obtained by the conventional droop techniques in (4).

If 𝑍𝑉 𝑆 = 𝑆. 𝐿𝑉 is considered, a virtual output inductance is emulated for the VSC.

In this case, the output voltage reference of the VSC is drooped proportional to the derivative

of its output current. In the presence of nonlinear loads, the harmonic currents can be

properly shared by modifying (3.20) as

𝑣𝑟𝑒𝑓 = 𝑣0∗ − 𝑆 𝐿𝑉𝐻𝐼𝐻 (3.21)

Where 𝐼𝐻 is the hth current harmonic, and 𝐿𝑉𝐻 is the inductance associated with 𝐼𝐻 .

𝐿𝑉𝐻 values need to be precisely set to effectively share the current harmonics. Since the

output impedance of the VSC is frequency dependent, in the presence of nonlinear loads,

THD of the output voltage would be relatively high. This can be mitigated by using a high-

pass filter instead 𝑠𝐿𝑣 of in

𝑣𝑟𝑒𝑓 = 𝑣0∗ − 𝐿𝑉

𝑆

𝑆+𝜔𝐶𝑖0 (3.22)

Where 𝜔𝐶 is the cutoff frequency of the high-pass filter

Figure.3.9 Virtual output impedance with voltage unbalance compensator

If the virtual impedance, 𝑍𝑉, is properly adjusted, it can prevent occurrence of current

spikes when the DER is initially connected to the microgrid. This soft starting can be

facilitated by considering a time-variant virtual output impedance as

𝑍𝑉 𝑡 = 𝑍𝑓 − (𝑍𝑓 − 𝑍𝑖)𝑒−

𝑡

𝑇 (3.23)

Where 𝑍𝑖 and 𝑍𝑓 are the initial and final values of the virtual output impedance,

respectively. T is the time constant of the start up process

Most recently, the virtual output impedance method has been modified for voltage

unbalance compensation, caused by the presence of unbalanced loads in the microgrid. The

block diagram of the modified virtual output impedance method is shown in Fig. 3.9. As can

be seen, the measured DER output voltage and current are fed into the positive and negative

sequence calculator (PNSC). Outputs of the PNSC 𝑖0+ 𝑖0

−, 𝑣0+, and 𝑣0

− , are used to find the

positive and negative sequence of the DER active and reactive power. The negative sequence

of the reactive power, 𝑄− , is multiplied by the 𝑣0− and then a constant gain, . The result is

then used to find the voltage reference. The constant gain needs to be fine-tuned to minimize

the voltage unbalance without compromising the closed-loop stability.

The virtual output impedance method alleviates the dependency of the droop

techniques on system parameters. Additionally, this control method properly operates in the

presence of nonlinear loads. However, this method does not guarantee the voltage regulation,

and, adjusting the closed loop time constant may result in an undesired deviation in the DER

voltage and frequency.

Figure.3.10.A typical two-DER system.

3.2.5.Signal Injection Method:

In this approach, each DER injects a small AC voltage signal to the microgrid.

Frequency of this control signal,𝜔𝑞 is determined by the output reactive power Q, of the

corresponding DER as

𝜔𝑞 = 𝜔𝑞0 + 𝐷𝑞𝑄 (3.24)

where 𝜔𝑞0 is the nominal angular frequency of injected voltage signals and 𝐷𝑞 is the boost

coefficient. The small real power transmitted through the signal injection is then calculated

and the RMS value of the output voltage of the DER, E, is accordingly adjusted as

𝐸 = 𝐸∗ − 𝐷𝑝𝑃 (3.25)

where 𝐸∗ is the RMS value of the no-load voltage of the DER, and 𝐷𝑝 is the droop

coefficient. This procedure is repeated until all VSCs produce the same frequency for the

control signal. Here, this technique is elaborated for a system of two DERs shown in Fig.

3.10. It is assumed that is the same for both DERs. Initially, first and second DERs inject low

voltage signals to the system with the following frequencies

𝜔𝑞1 = 𝜔𝑞0 + 𝐷𝑞𝑄1 (3.26)

𝜔𝑞2 = 𝜔𝑞0 + 𝐷𝑞𝑄2 (3.27)

Assuming 𝑄1 > 𝑄2

∆𝜔 = 𝜔𝑞1 − 𝜔𝑞2 = 𝐷𝑞 𝑄1 − 𝑄2 = ∆𝑄 (3.28)

The phase difference between the two voltage signals can be obtained as

𝛿 = ∆𝜔 𝑑𝑡 = 𝐷𝑄∆𝑄𝑡 (3.29)

Due to the phase difference between the DERs, a small amount of active power flows from

one to the other. Assuming inductive output impedances for DERs, the transmitted active

power from DER1 to DER2,𝑝𝑞1, is

𝑝𝑞1 =𝑣𝑞1+𝑣𝑞2

𝑥1+𝑥2+𝑋1+𝑋2 𝑠𝑖𝑛𝛿 (3.30)

where 𝑣𝑞1and 𝑣𝑞2 are the RMS values of the injected voltage signals. Moreover, the

transmitted active power in reverse direction, from DER2 to DER1 𝑝𝑞2, is

𝑝𝑞2 = −𝑝𝑞1

The DER voltages are adjusted as

𝐸 = 𝐸∗ − 𝐷𝑝𝑝𝑞1 (3.31)

𝐸 = 𝐸∗ − 𝐷𝑝𝑝𝑞2 (3.32)

Herein, it is assumed that 𝐷𝑝 is the same for both DERs. The difference between the DERs

output voltages is

∆𝐸 = 𝐸1 − 𝐸2 = −2𝐷𝑝𝑝𝑞1 (3.33)

The block diagram of the proposed controller is shown in below

Figure.3.11. Block diagram of the signal injection method for reactive power sharing

In the presence of nonlinear loads, parallel DERs can be controlled to participate in

supplying current harmonics by properly adjusting the voltage loop bandwidth. For that, first

frequency of the injected voltage is drooped based on the total distortion power, D.

𝜔𝑑 = 𝜔𝑑0 − 𝑚𝐷 (3.34)

𝐷 = 𝑆2 − 𝑃2 − 𝑄2 (3.35)

where 𝜔𝑑0 is the nominal angular frequency of the injected voltage signals, m is the droop

coefficient, and S is DER apparent power. A procedure similar to (39)–(42) is adopted to

calculate the power transmitted by the injected signal, 𝑝𝑑 . The bandwidth of VSC voltage

loop is adjusted as

𝐵𝑊 = 𝐵𝑊0 − 𝐷𝑏𝑤 𝑝𝑑 (3.36)

Where 𝐵𝑊0 is the nominal bandwidth of the voltage loop and 𝐷𝑏𝑤 is the droop coefficient.

The block diagram of the signal injection method is shown in Fig. 3.12.

Figure.3.12. Block diagram of the updated signal injection method

Signal injection method properly controls the reactive power sharing, and is not

sensitive to variations in the line impedances. It also works for linear and nonlinear loads,

and over various operating conditions. However, it does not guarantee the voltage regulation.

3.2.2.6.Nonlinear Load Sharing:

Some have challenged the functionality of droop techniques in the presence of

nonlinear loads. Two approaches for resolving this issue are discussed here. In the first

approach, the DERs equally share the linear and nonlinear loads. For this purpose, each

harmonic of the load current,𝐼𝑕 , is sensed to calculate the corresponding voltage droop

harmonic, 𝑉𝑕 , at the output terminal of the DER. The voltage harmonics are compensated by

adding 90 leading signals, corresponding to each current harmonic, to the DER voltage

reference. Therefore, the real and imaginary parts of the voltage droop associated with each

current harmonic are

𝑅𝑒 𝑉𝑕 = −𝐾𝑕 𝐼𝑚(𝐼𝑕) (3.37)

𝐼𝑚 𝑉𝑕 = 𝐾𝑕 𝑅𝑒(𝐼𝑕) (3.38)

where 𝐾𝑕 is the droop coefficient for the hth

harmonic. As a result, the output voltage THD is

significantly improved.

Figure.3.13. Control block diagram for the harmonic cancellation technique.

In the second approach, the conventional droop method is modified to compensate for

the harmonics of the DER output voltage. These voltage harmonics are caused by the

distorted voltage drop across the VSC output impedance and are due to the distorted nature

of the load current. As shown in Fig. 3.13, first, the DER output voltage and current are used

to calculate the fundamental term and harmonics of the DER output active and reactive

power (𝑃1, 𝑄1) and (𝑃𝑕 , 𝑄𝑕 ) respectively. It is noteworthy that distorted voltage and current

usually do not carry even harmonics, and thus, h is usually an odd number 𝑃1and 𝑄1, are fed

to the conventional droop characteristics to calculate the fundamental term, 𝑣0∗, of the VSC

voltage reference, 𝑣𝑟𝑒𝑓 . As shown in Fig. 3.13, to cancel out the output voltage harmonics, a

set of droop characteristics are considered for each individual harmonic. Each set of droop

characteristics determines an additional term to be included in the VSC output voltage

reference, 𝑣𝑟𝑒𝑓 , to cancel the corresponding voltage harmonic. Each current harmonic 𝑖𝑕 is

considered as a constant current source, as shown in Fig.3.14. In this figure, 𝐸𝑕∠δh denotes a

phasor for the corresponding voltage signal that is included in the voltage reference 𝑣𝑟𝑒𝑓 .

𝑍𝑕∠θh represents the VSC output impedance associated with the h th current harmonic.

Figure.3.14. h th harmonic equivalent circuit of a DER.

The active and reactive powers delivered to the harmonic current source, 𝑃𝑕and 𝑄𝑕 are

𝑃𝑕 = 𝐸𝑕 𝐼𝑕 cos 𝛿𝑕 − 𝑍𝑕 𝐼𝑕 2𝑐𝑜𝑠𝜃𝑕 (3.39)

𝑄𝑕 = 𝐸𝑕𝐼𝑕 sin 𝛿𝑕 − 𝑍𝑕 𝐼𝑕 2𝑠𝑖𝑛𝜃𝑕 (3.40)

When 𝛿𝑕 is small enough (i.e., sin(𝛿𝑕) = 𝛿𝑕 𝑃𝑕and 𝑄𝑕 are roughly proportional to 𝐸𝑕 and

𝛿𝑕 , respectively. Therefore, the following droop characteristics can be used to eliminate the

hth DER output voltage harmonic.

𝜔𝑕 = 𝑕𝜔∗ − 𝐷𝑕𝑄 𝑄𝑕 (3.41)

𝐸𝑕 = −𝐷𝑕𝑃 𝑃𝑕 (3.42)

where 𝜔∗is the rated fundamental frequency of the microgrid. 𝐷𝑕𝑃 and 𝐷𝑕𝑄 are the droop

coefficients. As can be seen in Fig.3.13, the harmonic reference voltage 𝑣𝑕𝑟𝑒𝑓

, for eliminating

the hth output voltage harmonic, can be formed with 𝐸𝑕 and the phase angle generated from

the integration of 𝜔𝑕 .

3.3 SECONDARY CONTROL

Primary control, as discussed, may cause frequency deviation even in steady

state. Although the storage devices can compensate for this deviation, they are unable to

provide the power for load-frequency control in long terms due to their short energy capacity.

The secondary control, as a centralized controller, restores the microgrid voltage and

frequency and compensate for the deviations caused by the primary control. This control

hierarchy is designed to have slower dynamics response than that of the primary, which

justifies the decoupled dynamics of the primary and the secondary control loops and

facilitates their individual designs.

Figure.3.15. Block Diagram of the Secondary and Tertiary Control

Figure 3.15 represents the block diagram of the secondary control. As seen in this

figure, frequency of the microgrid and the terminal voltage of a given DER are compared

with the corresponding reference values, 𝜔𝑟𝑒𝑓 and 𝐸𝑟𝑒𝑓 , respectively. Then, the error

signals are processed by individual controllers as in (4.14); the resulting signals ( 𝛿𝜔 and 𝛿𝐸 )

are sent to the primary controller of the DER to compensate for the frequency and voltage

deviations

𝛿𝜔 = 𝐾𝑃𝜔 𝜔𝑟𝑒𝑓 − 𝜔 + 𝐾𝐼𝜔 ( 𝜔𝑟𝑒𝑓 − 𝜔)𝑑𝑡 + ∆𝜔𝑆 (3.43)

𝛿𝐸 = 𝐾𝑃𝐸 𝐸𝑟𝑒𝑓 − 𝐸 + 𝐾𝐼𝐸 ( 𝐸𝑟𝑒𝑓 − 𝐸)𝑑𝑡 (3.44)

Where 𝐾𝑃𝜔 , 𝐾𝐼𝜔 , 𝐾𝑃𝐸 ,and 𝐾𝐼𝐸 are the controllers parameters. An additional

term, ∆𝜔𝑆 , is considered in frequency controller in (3.43&3.44) to facilitate synchronization

of the microgird to the main gird. In the islanded operating mode, this additional term is zero.

However, during the synchronization, a PLL module is required to measure ∆𝜔𝑆 . During the

grid-tied operation, voltage and frequency of the main grid are considered as the references

in (3.43).

Most recently, potential function-based optimization technique has been suggested for

the secondary control. In this method, a potential function is considered for each DER. This

function is a scalar cost function that carries all the information on the DER measurements,

constraints, and control objectives as

∅𝑗 𝑥𝑗 = 𝑤𝑢 𝑝𝑖𝑢𝑛𝑢

𝑖=1 𝑥𝑗 + 𝑤𝑐 𝑝𝑖𝑐𝑛𝑐

𝑖=1 𝑥𝑗 + 𝑤𝑔𝑝𝑗𝑔

(𝑥𝑗 ) (3.45)

Where ∅𝑗 is the potential function related to each DER, and 𝑥𝑗 comprises the

measurements from the DER unit (e.g., voltage, current, real and reactive power). 𝑝𝑖𝑢denotes

the partial potential functions that reflect the measurement information of the DER.

𝑝𝑖𝑐denotes the operation constraints that ensure the stable operation of microgrid. 𝑝𝑗

𝑔is used

to mitigate the DER measurements from the pre-defined set points. 𝑤𝑢 , 𝑤𝑐 and 𝑤𝑔 are the

weighted factors for the partial potential functions.

Figure.3.16. The potential function-based technique block diagram

The block diagram of the potential function-based technique is shown in Fig.3.16. In

this technique, when the potential functions approach their minimum values, the microgrid is

about to operate at the desired states. Therefore, inside the optimizer in Fig.3.16, set points of

the DER are determined such that to minimize the potential functions, and thus, to meet the

microgrid control objectives.

The potential function-based technique requires bidirectional communication

infrastructure to facilitate data exchange from the DER to the optimizer (measurements) and

vice versa (calculated set points). The data transfer links add propagation delays to the

control signals. This propagation delay is tolerable, since the secondary controllers are slower

than the primary ones.

The secondary control can also be designed to satisfy the power quality requirements,

e.g., voltage balancing at critical buses. Block diagram of the voltage unbalance compensator

is shown in Fig.3.17. First, the critical bus voltage is transformed to the dq reference frame.

Once the positive and negative sequence voltages for both d and q axis are calculated, one

can find the voltage unbalance factor (VUF) as

𝑉𝑈𝐹 = 𝑣𝑑

− 2

+ 𝑣𝑞−

2

𝑣𝑑+

2+ 𝑣𝑞

+ 2 (3.46)

where 𝑣𝑑+and 𝑣𝑑

−are the positive and negative sequence voltages of the direct component, and

𝑣𝑞+and 𝑣𝑞

− are the positive and negative sequence voltages of the quadrature component,

respectively.

Figure.3.17. Voltage unbalance Compensation in the Secondary Control

In Fig.3.17, the calculated VUF is compared with the reference value VUF*, and the

difference is fed to a PI controller. The controller output is multiplied by the negative

sequence of the direct and quadrature voltage components, 𝑣𝑑−

and 𝑣𝑞− , and the results are

added to the references of DER voltage controllers to compensate for the voltage unbalance.

3.4 TERTIARY CONTROL

Tertiary control is the last (and the slowest) control level that considers the

economical concerns in the optimal operation of the microgrid, and manages the power flow

between microgrid and main grid . In the grid-tied mode, the power flow between microgrid

and main grid can be managed by adjusting the amplitude and frequency of DERs voltages.

The block diagram of this process is shown in Fig.3.15. First, active and reactive output

powers of the microgrid, 𝑃𝐺and 𝑄𝐺 , are measured. These quantities are then compared with

the corresponding reference values, 𝑃𝐺𝑟𝑒𝑓

and 𝑄𝐺𝑟𝑒𝑓

, to obtain the frequency and voltage

references, 𝜔𝑟𝑒𝑓 and 𝐸𝑟𝑒𝑓 based on

𝜔𝑟𝑒𝑓 = 𝐾𝑃𝑃 𝑃𝐺𝑟𝑒𝑓

− 𝑃𝐺 + 𝐾𝐼𝑃 (𝑃𝐺𝑟𝑒𝑓

− 𝑃𝐺)𝑑𝑡 (3.47)

𝐸𝑟𝑒𝑓 = 𝐾𝑃𝑄 𝑄𝐺𝑟𝑒𝑓

− 𝑄𝐺 + 𝐾𝐼𝑄 ( 𝑄𝐺𝑟𝑒𝑓

− 𝑄𝐺)𝑑𝑡 (3.48)

Where 𝐾𝑃𝑃 , 𝐾𝐼𝑃 , 𝐾𝑃𝑄 and 𝐾𝐼𝑄 are the controllers parameters. 𝜔𝑟𝑒𝑓 and 𝐸𝑟𝑒𝑓 are

further used as the reference values to the secondary control.

CHAPTER 4

HIERARCHICAL SCHEME FOR VOLTAGE HARMONICS

AND UNBALANCE COMPENSATION

4.1. INTRODUCTION

Power Quality is a key issue in microgrids and common problems are voltage

unbalance and harmonics. Unbalanced voltages can result in adverse effects on equipment

and power system. Under unbalanced conditions, the power system will incur more losses

and be less stable. In addition, voltage unbalance has some negative impacts on equipment

such as induction motors, power electronic converters, and adjustable speed drives (ASDs).

Thus, the International Electrotechnical Commission (IEC) recommends the limit of 2% for

voltage unbalance in electrical systems. One major cause of voltage unbalance is the

connection of unbalanced loads (mainly, single-phase loads connection between two phases

or between one phase and the neutral).

Due to increasing of different non linear loads in electrical systems resulted in the

voltage harmonic distortion. This distortion can cause variety of problems such as protective

relays malfunction, overheating of motors and transformers and failure of power factor

correction capacitors. To mitigate these problems, a hierarchical control scheme is proposed

for enhancement of sensitive load bus voltage quality in microgrids. The control structure

consists of primary, secondary and tertiary levels. The primary control level comprises

distributed generators (DGs) local controllers. The local controllers mainly consist of power,

voltage and current controllers, and a selective virtual impedance loop which is considered to

improve sharing of fundamental and harmonic components of load current among the DG

units. The sharing improvement is provided at the expense of increasing voltage unbalance

and harmonic distortion. Thus, the secondary control level is applied to manage the

compensation of SLB voltage unbalance and harmonics by sending proper control signals to

the primary level. DGs compensation efforts are controlled locally at the primary level. The

tertiary control manages the power flow between microgrid and main grid. In the grid-tied

mode, the power flow between microgrid and main grid can be managed by adjusting the

amplitude and frequency of DGs voltage.

4.2. PRIMARY CONTROL LEVEL

The control of the DG inverter is based on three control loops : 1) the inner voltage

and current control loops; 2) the intermediate virtual impedance loop; and 3) the outer active

and reactive-power-sharing loops.

Figure 4.1 Block Diagram of Primary Controller

4.2.1. VOLTAGE AND CURRENT CONTROL LOOPS

Due to the difficulties of using PI controllers to track non-dc variables, proportional-

resonant (PR) controllers are usually preferred to control the voltage and current in the

stationary reference frame

𝐺𝑉 𝑠 = 𝐾𝑝𝑉 +2𝐾𝑟𝑉 .𝜔𝑐𝑉 .𝑠

𝑠2+2𝜔𝑐𝑉 .𝑠+𝜔02 (4.1)

𝐺𝐼 𝑠 = 𝐾𝑝𝐼 +2𝐾𝑟𝐼 .𝜔𝑐𝐼 .𝑠

𝑠2+2𝜔𝑐𝐼 .𝑠+𝜔02 (4.2)

where, 𝐾𝑝𝑉 (𝐾𝑝𝐼 ) and 𝐾𝑟𝑉 (𝐾𝑟𝐼) are the proportional and resonant coefficients of the

voltage (current) controller, respectively. Also, 𝜔𝑐𝑉 and 𝜔𝑐𝐼 represent the voltage and

current controller cut-off frequencies, respectively.

𝐺𝑉 𝑠 = 𝐾𝑝𝑉 + 2𝐾𝑟𝑉𝐾 .𝜔𝑐𝑉 .𝑠

𝑠2+2𝜔𝑐𝑉 .𝑠+(𝐾𝜔0)2𝐾=1,3,5,7 (4.3)

𝐺𝐼 𝑠 = 𝐾𝑝𝐼 + 2𝐾𝑟𝐼𝐾 .𝜔𝑐𝑉 .𝑠

𝑠2+2𝜔𝑐𝐼 .𝑠+(𝐾𝜔0)2𝐾=1,3,5,7 (4.4)

where 𝐾𝑝𝑉 (𝐾𝑝𝐼 )and 𝐾𝑟𝑉 (𝐾𝑟𝐼)are the proportional and Kth harmonic (including

fundamental component as the first harmonic) resonant coefficients of the voltage (current)

controller, respectively. 𝜔𝑐𝑉 and 𝜔𝑐𝐼 represent voltage and current controllers cut-off

frequencies, respectively.

4.2.2. VIRTUAL IMPEDANCE LOOP

The accuracy of the power sharing provided by the droop controllers is affected by

the output impedance of the DG units and the line impedances. The virtual impedance is a

fast control loop that can fix the phase and magnitude of the output impedance. Moreover,

the effect of asymmetrical line impedances can be mitigated by proper design of the virtual

impedance loop

Addition of the virtual resistance makes the oscillations of the system more damped.

In contrast with physical resistance, the virtual resistance has no power losses, and it is

possible to implement it without decreasing the efficiency. Also, the virtual inductance is

considered to ensure the decoupling of 𝑅𝑣 and𝐿𝑣 . Thus, virtual impedance makes the droop

controllers more stable. The virtual impedance can be achieved as shown in Fig. 4.2, where

and are the virtual resistance and inductance, respectively. According to this figure, the

following equations are extracted:

Figure.4.2. Fundamental virtual impedance loop

𝑣𝑉𝛼 = 𝑅𝑣 . 𝑖0𝛼+ − 𝐿𝑣 . 𝜔. 𝑖0𝛽

+ (4.5)

𝑣𝑉𝛽 = 𝑅𝑣 . 𝑖0𝛽+ + 𝐿𝑣 . 𝜔. 𝑖0𝛼

+ (4.6)

Virtual impedance can improve the sharing of nonlinear (harmonic) load among

parallel converters. Hence, the basic structure is extended by including virtual resistances for

the fundamental negative sequence 𝑅𝑣𝑟1−and the main harmonic components (𝑅𝑣𝑟

𝑕−,h=3,5 and

7) of the DG output current in order to improve the sharing of these current components.

Figure.4.3.Selective Virtual impedance

The sharing improvement is achieved at the expense of distorting DGs output voltage

as a result of voltage drop on the virtual resistances. Thus, for selection of virtual resistance

values, a trade-off should be considered between the amount of output voltage distortion and

sharing accuracy.

4.2.3. REAL & REACTIVE POWER CONTROLLER LOOP

Considering a DG connected to the grid through the impedance, the active and

reactive powers injected to the grid by the DG can be expressed as follows

𝑃 = 𝐸 𝑉 cos ∅

𝑍−

𝑉2

𝑍 𝑐𝑜𝑠𝜃 +

𝐸 𝑉 sin ∅.𝑠𝑖𝑛𝜃

𝑍 (4.7)

𝑄 = 𝐸 𝑉 cos ∅

𝑍−

𝑉2

𝑍 𝑠𝑖𝑛𝜃 −

𝐸 𝑉 sin ∅.𝑠𝑖𝑛𝜃

𝑍 (4.8)

where is the magnitude of the inverter output voltage, is the grid voltage magnitude,

∅ is the load angle (the angle between E and V ), and Z and 𝜃 are the magnitude and the

phase angle of the impedance, respectively. Considering phase angle of the grid voltage to be

zero, ∅ will be equal to phase angle of the inverter voltage.

Assuming mainly inductive electrical systems (Z ≈ 𝑋 and ≈ 90° ), the active and reactive

powers can be expressed as the following equations:

𝑃 ≈ 𝐸 𝑉 sin ∅

𝑋 (4.8)

𝑄 ≈ 𝐸 𝑉 cos ∅−𝑉2

𝑋 (4.9)

In practical applications, ∅ is normally small; thus, a 𝑃 𝑄 decoupling approximation ( ∅ = 1

and 𝑠𝑖𝑛∅ = ∅ ) can be considered as follows

𝑃 ≈ 𝐸 𝑉 ∅

𝑋 (4.10)

𝑄 ≈ 𝐸 𝑉−𝑉2

𝑋 (4.11)

Thus, active and reactive powers can be controlled by the DG output voltage phase

angle and amplitude, respectively. According to this, the following droop characteristics are

applied for the positive sequence active and reactive power sharing among DGs in an

islanded microgrid:

∅∗ =𝜔∗

𝑠=

1

𝑠 𝜔0 − 𝑚𝑝 + 𝑚𝑑𝑠 𝑃+ (4.12)

𝐸∗ = 𝐸0 − 𝑛𝑃𝑄+ (4.13)

Where, • S: Laplace variable;

• 𝐸0: rated voltage amplitude;

• 𝜔0: rated angular frequency;

• 𝑃+: positive sequence active power;

• 𝑄+: positive sequence reactive power;

• 𝑚𝑃 : active power proportional coefficient;

• 𝑚𝑑 : active power derivative coefficient;

•𝑛𝑃: reactive power proportional coefficient;

• 𝐸∗: voltage amplitude reference;

• ∅∗: voltage phase angle reference;

• 𝜔∗: angular frequency reference.

The derivative coefficient in 𝑚𝑑 , helps to improve the dynamic behavior of the

power control. It is noteworthy that according to the (4.12) and (4.13), no integral term is

considered for voltage frequency and amplitude control. If the microgrid operates in islanded

mode (the case considered in this thesis) the use of pure integrators is not allowed; since, the

total load will not coincide with the total injected power, and it leads to instability.

4.2.4. COMPENSATION EFFORT CONTROLLER

The compensation effort controller manages the sharing of compensation workload

among the microgrid DGs. The block diagram of effort controller is shown in Fig. 4.4.As

seen, DG unit output current in 𝛼𝛽frame (𝑖0𝛼𝛽 )is fed to this controller and positive and

negative sequences of its -axis fundamental component ( 𝑖0𝛼1+ and 𝑖0𝛼

1− ) and hth harmonic

component (𝑖0𝛼𝑕+ and 𝑖0𝛼

𝑕− ) are extracted. Then, 𝑖0𝛼1+ 𝑖0𝛼

1− 𝑖0𝛼𝑕+ and 𝑖0𝛼

𝑕− are applied to calculate

current unbalance factor UFI and harmonic distortion indices of hth harmonic positive and

negative sequences (𝐻𝐷𝐼𝑕+and 𝐻𝐷𝐼

𝑕− , respectively). UFI , 𝐻𝐷𝐼𝑕+ 𝐻𝐷𝐼

𝑕− calculated as the

ratio of 𝑖0𝛼1− 𝑖0𝛼

𝑕+ and 𝑖0𝛼𝑕− rms values (𝐼0𝛼

1−, 𝐼0𝛼𝑕+and 𝐼0𝛼

𝑕−, respectively) to rms value of 𝑖0𝛼1+(𝐼0𝛼

1+),

respectively. Note that using -components for calculation of unbalance and harmonic

distortion indices leads to the same results because the magnitude of α- and β-components is

equal for both positive and negative sequences of fundamental and harmonic components.

Finally, the references for compensation of fundamental unbalance and hth harmonic

positive and negative sequences by DGj (𝐶𝑑𝑞1− 𝐶𝑑𝑞

𝑕+and𝐶𝑑𝑞𝑕− , respectively) are calculated as

shown in Fig. 4.4 where 𝑆0𝑗 is the rated capacity of DGj and subscript “max” represent the

maximum value. By multiplying the ratio of DGj rated capacity (𝑆0𝑗 )to the total capacity of

the microgrid DGs 𝑆0𝑗𝑛𝑙=1 , compensation effort of each DG will be proportional to its rated

capacity.

Figure.4.4.Block diagram of compensation effort controller

UFI,𝐻𝐷𝐼𝑕+and 𝐻𝐷𝐼

𝑕−can be considered as the indices of compensation effort because

as shown in the simulation results, compensation of SLB voltage unbalance and hth harmonic

positive and negative sequences is achieved through injecting corresponding current

components by the DGs. Thus, the terms ( 𝑈𝐹𝐼,𝑀𝐴𝑋 − 𝑈𝐹𝐼 ) (𝐻𝐷𝐼,𝑀𝐴𝑋𝑕+ − 𝐻𝐷𝐼

𝑕+) and

(𝐻𝐷𝐼,𝑀𝐴𝑋𝑕+ − 𝐻𝐷𝐼

𝑕+) in Fig. 4.4 contribute towards sharing of compensation effort. In fact,

increase of each component compensation effort leads to the increase of corresponding

index. Consequently, ( 𝑈𝐹𝐼,𝑀𝐴𝑋 − 𝑈𝐹𝐼), (𝐻𝐷𝐼,𝑀𝐴𝑋𝑕+ − 𝐻𝐷𝐼

𝑕+) or (𝐻𝐷𝐼,𝑀𝐴𝑋𝑕+ − 𝐻𝐷𝐼

𝑕+) decrease

and it leads to compensation effort decrease. So, inherent negative feedbacks exist in the

effort controller. It is assumed that the maximum values of unbalance factor and harmonic

distortion indices are unity. This assumption is valid for most of the practical cases; however,

larger constants can be used as the maximum values.

4.3. SECONDARY CONTROL LEVEL

4.3.1 VOLTAGE UNBALANCE COMPENSATION:

The secondary controller manages the unbalance compensation of microgrid PCC

voltage by sending proper control signals to the DGs local controllers. The secondary

controller can be far from DGs and PCC. Thus, as shown in Fig.4.5, a low bandwidth

communication link (LBCL) is considered to send the PCC voltage information to this

controller. Also, the control signal for voltage unbalance compensation (𝑈𝐶𝑅𝑑𝑞 : Unbalance

Compensation Reference) is transmitted by means of LBCL to the primary level.

In order to ensure that low bandwidth is sufficient, the transmitted data should be

approximately dc signals. Thus, the data are transmitted in dq reference frame. Afterwards,

two 2nd order low-pass filters (LPF) are used to extract positive and negative sequences

(𝑣𝑑𝑞+ and 𝑣𝑑𝑞

− , respectively). 2nd order LPFs are applied, since, the 1st order ones cannot

provide acceptable filtering. The transfer function of LPFs is as follows:

𝐿𝑃𝐹 =𝜔𝑐𝑢𝑡

2

𝑠2+2𝜉𝜔𝑐𝑢𝑡 𝑠+𝜔𝑐𝑢𝑡2 (4.16)

Figure.4.5. Block diagram of Secondary Control level for unbalance compensation

where 𝑣𝑑+ and 𝑣𝑑

− are the positive and negative sequence voltages of the direct

component, and 𝑣𝑞+and 𝑣𝑞

− are the positive and negative sequence voltages of the quadrature

component, respectively. As depicted in Fig.4.5, the calculated VUF is compared with the

reference value VUF*, and the difference is fed to a PI controller. The controller output is

multiplied by the negative sequence of the direct and quadrature voltage components, 𝑣𝑑−

and

𝑣𝑞− , to generate 𝑈𝐶𝑅𝑑𝑞 which is transmitted to the primary level.

As shown in Fig.4.1, at first,𝑈𝐶𝑅𝑑𝑞 is transformed to 𝛼𝛽frame and then added as a

reference for voltage controller. It is noteworthy that this transformation is performed over

negative sequence values; thus, ∅∗is used as the rotation angle. ∅∗is the DG voltage reference

phase angle which is generated by active power droop controller

4.3.2 VOLTAGE HARMONIC COMPENSATION:

The above control technique increases voltage unbalance at the output of the interface

inverter. It is vulnerable to suffer from more distortions with higher order harmonics, with

non-linear loads in the network. In addition to that, virtual impedance loop increases the

harmonic voltage distortion and increases the output voltage unbalance at the interface

inverter. This is handled by implementing a selective harmonic compensation technique for

different higher order harmonics (e.g. 5th, 7th, 11th and 13th).

Figure.4.6. Block diagram of Secondary Control level for harmonic compensation

The block diagram of the central secondary controller is shown in Fig. 4.6. As can be

seen in the “Harmonics Compensation” block, 𝑣𝑑𝑞1 , 𝑣𝑑𝑞

5 , and 𝑣𝑑𝑞7 are used to calculate 5th

and 7th order harmonic distortions (HD5 and HD7, respectively). Then, the calculated values

are compared with the reference ones (𝐻𝐷5∗, 𝐻𝐷7

∗ respectively). The errors are fed to the

proportional integral (PI) controllers. Afterwards, the outputs of these controllers are

multiplied by 𝑣𝑑𝑞5 and 𝑣𝑑𝑞

7 to generate 𝐻𝐶𝑅𝑑𝑞5 and 𝐻𝐶𝑅𝑑𝑞

7 , respectively. If any of the

harmonic distortions is less than the reference value, the respective deadband block prevents

the increase of the distortion by the PI controller.

CHAPTER 5

SIMULATION RESULTS

In this chapter two cases results are presented. In case 1, the simulation results of

voltage unbalance compensation considering a linear unbalanced load are presented. In case

2 the simulation results of sensitive load bus (SLB) voltage unbalance and harmonics

compensation considering a non linear unbalanced load

5.1. CASE-1(PRESENCE OF LINEAR UNBALANCED LOAD)

The islanded microgrid of fig.5.1. is considered as the test system, This microgrid

includes two DGs with power stage and control system. Switching frequency of the DGs

inverters is set to 10 kHz. A single-phase load is connected between phases “a” and “b”

which creates voltage unbalance. A balanced star-connected three-phase load is also

connected to PCC. In this figure, ZL1 and ZL2 represent the distribution lines between DGs

and PCC.

Figure.5.1. Test System of Islanded Microgrid with Unbalanced load

Fig

ure

.5.1

.1 M

atla

b/S

imuli

nk M

odel

for

Isla

nded

mic

rogri

d w

ith l

inea

r unbal

ance

d l

oad

BEFORE COMPENSATION:-

Before activating the secondary controller at t=0.25 sec, DGs output voltages are

approximately free of voltage unbalance but PCC voltage becomes unbalanced

Figure.5.1.2 Voltage Waveform of DG1 (Before compensation)

Figure.5.1.3 Voltage Waveform of DG2 (Before compensation)

Figure.5.1.4 Voltage Waveform of PCC (Before compensation)

AFTER COMPENSATION:-

After activating the secondary controller at t=0.25 sec, the result of compensation,

PCC voltage unbalance is decreased, effectively while the DGs output voltage becomes

unbalanced

Figure.5.1.5 Voltage Waveform of DG1 (After compensation)

Figure.5.1.6 Voltage Waveform of DG2 (After compensation)

Figure.5.1.7 Voltage Waveform of PCC (After compensation)

At 0≤t<2.5 (Before Compensation):-

Figure.5.1.8 Phase-a Negative Sequence Voltage Waveform of PCC, DG1

At 2.5≤t<4.0 (After Compensation):-

Figure.5.1.9 Phase-a Negative Sequence Voltage Waveform of PCC, DG1

Figure.5.1.10 Voltage Unbalance factor (VUF) of PCC, DG1, DG2

5.2. CASE-2(PRESENCE OF NON-LINEAR UNBALANCED LOAD)

Fig.5.2.shows the simulation test system which is a two-DG islanded microgrid

comprising two source buses, one sensitive load bus, and one non sensitive load bus. A diode

rectifier and a star-connected linear load are connected to SLB. It is assumed that one phase

of nonlinear load is disconnected to create unbalanced voltage distortion. Furthermore, a

balanced nonlinear load is connected to NLB. Switching frequency of the DGs inverters is 10

kHz. The test system parameters are listed in Appendix. Note that in this parameters, the

impedances of linear load and lines are presented in terms of resistance and inductance.

Simulations are performed using MATLAB/Simulink. Three simulation steps are considered:

• Step1 (0≤ 𝑡 < 0.2)

DGs operate only with fundamental positive sequence virtual impedance and secondary

control is not acting.

• Step2 (0.2≤ 𝑡 < 0.4)

Virtual resistances for fundamental negative sequence and harmonic components are added.

• Step3 (0.4 ≤ 𝑡 < 0.6)

Secondary control is activated. The reference values of unbalance factor and harmonic

distortion indices are 0.2%.

Figure.5.2. Test System of Islanded Microgrid with Non linear unbalanced load

Fig

.5.2

.1 M

atla

b/S

imuli

nk M

odel

for

Isla

nded

mic

rogri

d w

ith N

on l

inea

r unbal

ance

d l

oad

Step-1(𝟎 ≤ 𝒕 < 0.2) :-

Before activating the virtual resistances for fundamental negative sequence and

harmonic components, DGs output voltages are approximately free of distortion. SLB

voltage is distorted noticeably due to voltage drops on distribution lines.

Figure.5.2.2 Voltage Waveform of Source Bus_1 (SB1) at 𝟎 ≤ 𝒕 < 0.2

Figure.5.2.3 Voltage Waveform of Source Bus_2 (SB2) at 𝟎 ≤ 𝒕 < 0.2

Figure.5.2.4 Voltage Waveform of Sensitive Load Bus (SLB) at 𝟎 ≤ 𝒕 < 0.2

Figure 5.2.5 Harmonic Spectrum Analysis of Sensitive load bus voltage at 𝟎 ≤ 𝒕 < 0.2

Fig.5.2.6 Fundamental Negative Sequence Current of DG1, DG2 at 0 ≤ 𝑡 < 0.2

Fig.5.2.7 3rd

Harmonic Sequence Currents of DG1, DG2 at 0 ≤ 𝑡 < 0.2

Fig.5.2.6 and Fig.5.2.7 shows negative sequence single-phase waveforms at

fundamental and 3rd harmonic frequencies. considering double rating of DG1, it can be

noticed from Fig.5.2.6 and Fig.5.2.7 that the load current is not properly shared in the first

simulation step. In fact, all components of the load current except fundamental positive

sequence one are shared according to the test system topology and before adding

𝑅𝑣𝑟1− 𝑅𝑣𝑟

3 𝑅𝑣𝑟 5 𝑎𝑛𝑑 𝑅𝑣𝑟

7 ,DG2 will supply larger portions of the fundamental negative sequence

and the harmonic currents.

Fig.5.2.8 DG1 Output current at 0 ≤ 𝑡 < 0.2

Fig.5.2.9 DG2 Output current at 0 ≤ 𝑡 < 0.2

Step-2(𝟎. 𝟐 ≤ 𝒕 < 0. 𝟒) :-

Virtual resistances for fundamental negative sequence and harmonic components are

added. The sharing improvement is achieved at the expense of voltage distortion increase at

DGs terminals and consequently at SLB.

Fig.5.2.10 Voltage Waveform of Source Bus_1 (SB1) at 𝟎. 𝟐 ≤ 𝒕 < 0. 𝟒

Fig.5.2.11 Voltage Waveform of Source Bus_2 (SB2) at 𝟎. 𝟐 ≤ 𝒕 < 0. 𝟒

Fig.5.2.12 Voltage Waveform of Sensitive Load Bus (SLB) at 𝟎. 𝟐 ≤ 𝒕 < 0. 𝟒

Figure 5.2.13 Harmonic Spectrum Analysis of Sensitive load bus voltage at 𝟎. 𝟐 ≤ 𝒕 < 0.4

In this step i.e., 0.2 ≤ 𝑡 < 0.4, the current sharing is improved noticeably. however, it still is

not in proportion to the DGs rated powers.

Fig.5.2.14 Fundamental Negative Sequence Current of DG1, DG2 at 0.2 ≤ 𝑡 < 0.4

Fig.5.2.15 3rd

Harmonic Sequence Currents of DG1, DG2 at 0.2 ≤ 𝑡 < 0.4

Fig.5.2.16 DG1 Output current at 0.2 ≤ 𝑡 < 0.4

Fig.5.2.17 DG2 Output current at 0.2 ≤ 𝑡 < 0.4

Step-3 (𝟎. 𝟒 ≤ 𝒕 < 0. 𝟔) :-

In the last simulation step, selective compensation of SLB voltage main harmonics

and fundamental negative sequence component is activated at t=0.4s. SLB voltage quality is

significantly improved as seen in fig.5.2.18-fig.5.2.20 Furthermore, it can be observed in

Fig.5.2.20 that the compensation is achieved by the increase of output DG1 voltage distortion.

Fig.5.2.18 Voltage Waveform of Source Bus_1 (SB1) at 𝟎. 𝟒 ≤ 𝒕 < 0. 𝟔

Fig.5.2.19 Voltage Waveform of Source Bus_2(SB2) at 𝟎. 𝟒 ≤ 𝒕 < 0. 𝟔

Fig.5.2.20 Voltage Waveform of Sensitive Load Bus (SLB) at 𝟎. 𝟒 ≤ 𝒕 < 0. 𝟔

Figure 5.2.21 Harmonic Spectrum Analysis of Sensitive load bus voltage at 𝟎. 𝟒 ≤ 𝒕 < 0.6

Note that the impedance of the distribution line between and SLB is relatively high;

also, the fundamental negative sequence and harmonic components of the load which are

supplied by this DG are approximately twice of the amounts of DG2. Thus, in order to

compensate the voltage drops on the lines and the virtual resistances and provide

approximately sinusoidal voltage at SLB, DG1 output voltage becomes noticeably distorted.

On the other hand, due to low value of the line impedance between SB2 and SLB and also

lower load portion of DG2, the distortions of SLB and DG2 voltages change with a similar

behavior

Fig.5.2.22 Fundamental Negative Sequence Current of DG1, DG2 at 0.4 ≤ 𝑡 < 0.6

Fig.5.2.23 3rd

Harmonic Sequence Currents of DG1, DG2 at 0.4 ≤ 𝑡 < 0.6

Fig.5.2.24 DG1 Output current at 0.4 ≤ 𝑡 < 0.6

Fig.5.2.25 DG2 Output current at 0.4 ≤ 𝑡 < 0.6

Fig.5.2.26 Positive sequence real powers of DG1,DG2

Fig.5.2.27 Positive sequence reactive powers of DG1,DG2

CONCLUSION

In this thesis, the control of Distributed Generators interface converters are used in

order to improve the microgrid power quality is discussed. A hierarchical control approach to

compensate voltage unbalance and harmonics in an islanded microgrid is proposed. The

control structure consists of primary and secondary control levels. The secondary controller

manages voltage unbalance in microgrid by sending proper control signals to primary level.

Harmonics in microgrids are reduced by selective compensation of Sensitive load bus

voltage fundamental negative sequence, positive and negative sequences of main harmonics

by sending proper control signals to the primary level. Selective harmonic compensation

method is shown to ensure voltage balance even without disconnecting the unbalanced or

non-linear loads.

FUTURE SCOPE

Power quality problem such as voltage sag compensation can also be implemented by

using hierarchical scheme

Synchronization of grid connected microgrid and utility grid can also be implemented

by using hierarchical scheme

REFERENCES

[1] IEEE Guide for Design, Operation, and Integration of Distributed Resource Island

Systems With Electric Power Systems, IEEE Std. 1547.4- 2011, 2011.

[2] M. Cirrincione, M. Pucci, and G. Vitale, “A single-phase DG generation unit with shunt

active power filter capability by adaptive neural filtering,” IEEE Trans. Ind. Electron., vol.

55, no. 5, pp. 2093–2110, May 2008.

[3] T. L. Lee and P. T. Cheng, “Design of a new cooperative harmonic filtering strategy for

distributed generation interface converters in an islanding network,” IEEE Trans. Power

Electron., vol. 22, no. 5, pp. 1919–1927, Sep. 2007.

[4] P. T. Cheng, C. Chen, T. L. Lee, and S. Y. Kuo, “A cooperative imbalance compensation

method for distributed-generation interface converters,” IEEE Trans. Ind. Appl., vol. 45, no.

2, pp. 805–815, Mar./Apr. 2009.

[5] Y. Li, D. M. Vilathgamuwa, and P. C. Loh, “Microgrid power quality enhancement using

a three-phase four-wire grid-interfacing compensator,” IEEE Trans. Ind. Appl., vol. 41, no. 6,

pp. 1707–1719,Nov./Dec. 2005.

[6] A. Mehrizi-Sani and R. Iravani, “Potential-function based control of a microgrid in

islanded and grid-connected modes,” IEEE Trans. Power Syst., vol. 25, no. 4, pp. 1883–

1891, Nov. 2010.

[7] J. M. Guerrero, J. C. Vasquez, J. Matas, L. G. de Vicuña, and M.Castilla, “Hierarchical

control of droop-controlled AC and DC microgrids a general approach toward

standardization,” IEEE Trans. Ind. Electron., vol. 58, no. 1, pp. 158–172, Jan. 2011.

[8] J. C. Vasquez, J. M. Guerrero, A. Luna, P. Rodriguez, , R. Teodorescu,“Adaptive droop

control applied to voltage-source inverters operating in grid-connected and islanded modes,”

IEEE Trans. Ind. Electron., vol. 56, no. 10, pp. 4088–4096, Oct. 2009.

[9] M. Savaghebi, A. Jalilian, J. C. Vasquez, and J. M. Guerrero, “Autonomous voltage

unbalance compensation in an islanded droop-controlled microgrid,” IEEE Trans. Ind.

Electron., vol. 60, no. 04, April 2013.

[10] J. M. Guerrero, J. C. Vásquez, J. Matas, M. Castilla, and L. G. D. Vicuña, “Control

strategy for flexible microgrid based on parallel line-interactive UPS systems,” IEEE Trans.

Ind. Electron., vol. 56, pp. 726–736, Mar. 2009.

[11] J. M. Guerrero, J. Matas, L. G. de Vicuña, M. Castilla, and J. Miret,“Decentralized

control for parallel operation of distributed generation inverters using resistive output

impedance,” IEEE Trans. Ind. Electron., vol. 54, no. 2, pp. 994–1004, Apr. 2007.

[12] F. Katiraei and M. R. Iravani, “Power management strategies for a microgrid with

multiple distributed generation units,” IEEE Trans. Power Syst., vol. 21, no. 4, pp. 1821–

1831, Nov. 2006.

[13] U. Borup, F. Blaabjerg, and P. N. Enjeti, “Sharing of nonlinear load in parallel-

connected three-phase converters,” IEEE Trans. Ind. Appl., vol. 37, no. 6, pp. 1817–1823,

Nov./Dec. 2001.

[14] J. He and Y.W. Li, “Analysis and design of interfacing inverter output virtual impedance

in a low voltage microgrid,” in Proc 2010 Energy Convers. Congr. Exp. (ECCE), pp. 2857–

2864.

APPENDIX

PARAMETERS

1. DG parameters:-

DC Link Voltage, Vdc (V) =650

LC Filter Inductance, L(mh)=1.8

LC Filter Capacitance, C(𝜇𝐹)=25

Nonlinear Loads Tie Lines, Z(Ω, 𝑚𝑕)=0.1, 1.6

Distribution Lines Z1,Z2,Z3(Ω, 𝑚𝑕)=0.1, 1.8

Non Linear Loads CNL/RNL1,RNL2/LNL (𝜇𝐹)/ (Ω)/ (mh) =235/50,

200/0.084

Linear Load ZL(Ω, 𝑚𝑕)=50,20

2. Primary Controller Parameters:-

Power Controllers(DG1/DG2)

𝑚𝑑 (𝑟𝑎𝑑/𝑤)=0.6× 10−5/1.2 × 10−3

𝑚𝑝(𝑟𝑎𝑑/𝑤. s)=0.6 × 10−4/1.2 × 10−4

𝑛𝑝(𝑉/𝑉𝐴𝑅)=1.4 × 10−1/2.8 × 10−1

Virtual Impedance(DG1/DG2)

𝑅𝑣𝑟1+ Ω = 0.3/0.6

𝐿𝑣𝑟 𝑚𝑕 = 2.5/5

𝑅𝑣𝑟1− Ω = 1.5/3.0

𝑅𝑣𝑟3 Ω = 2/4

𝑅𝑣𝑟5 Ω = 4/8

𝑅𝑣𝑟7 Ω = 4/8

Voltage/Current Controllers

𝐾𝑝𝑣 /𝐾𝑝𝑖 = 1/5

𝐾𝑟𝑣1/𝐾𝑟𝑖1 = 100/1000

𝐾𝑟𝑣3/𝐾𝑟𝑖3 = 200/400

𝐾𝑟𝑣5/𝐾𝑟𝑖5 = 50/100

𝐾𝑟𝑣7/𝐾𝑟𝑖7 = 100/100

𝜔𝑐𝑣 /𝜔𝑐𝑖 = 2/2

3. Secondary PI Controllers:-

Fundamental Negative Sequence

Proportional=3

Integral=90

3rd

Harmonic Positive and Negative Sequences

Proportional=1.25

Integral=110

5th Harmonic positive and Negative Sequences

Proportional=1

Integral=150

7th Harmonic positive and Negative Sequences

Proportional=0.95

Integral=200

AUTHOR’S PUBLICATION

Naveen Bolisetti and Mothi Ram Bhukya, “Hierarchical Control Scheme for

Compensation of Voltage Harmonics and Unbalance in Microgrids” proc. Advances

and Applications of Power Systems, Power Electronics and Solar Energy (AAPPS-

13), on 24th-25

th oct-2013, JNTUHCEJ, Karimnagar.

Naveen Bolisetti and Mothi Ram Bhukya, “Secondary Control Scheme for

Compensation of Voltage Harmonics and Unbalance in Microgrids” International

Journal of Engineering Research And Innovative Applications, ISSN: 2248-9278/Sep-

Oct13/Vol-1/Issue-3/Pg. 1041 1048.