power system restoration using dfig-based wind …
TRANSCRIPT
The Pennsylvania State University
The Graduate School
College of Engineering
POWER SYSTEM RESTORATION USING DFIG-BASED WIND
FARMS AND VSC-HVDC LINKS
A Thesis in
Electrical Engineering
by
Pooyan Moradi Farsani
© 2018 Pooyan Moradi Farsani
Submitted in Partial Fulfillment
of the Requirements
for the Degree of
Master of Science
August 2018
The thesis of Pooyan Moradi Farsani was reviewed and approved∗ by the following:
Nilanjan Ray Chaudhuri
Assistant Professor of Electrical Engineering
Thesis Advisor
Mehdi Kiani
Assistant Professor of Electrical Engineering
Kultegin Aydin
Professor of Electrical Engineering
Head of Electrical Engineering Department
∗Signatures are on file in the Graduate School.
ii
Abstract
Application of Voltage Sourced Converter High Voltage DC (VSC-HVDC) linksin power system restoration has been demonstrated in literature through detailedElectromagnetic Transient (EMT)-type models of very small-scale systems. How-ever, studying restoration of large power systems using such detailed models iscomputationally prohibitive. In this thesis, a hybrid simulation platform is proposedfor such studies in which a significant portion of the system, for which developing adetailed three phase model is not necessary, is modelled in a phasor framework andis co-simulated with a detailed EMT-type model of a smaller portion containingVSC-HVDC link. Moreover, in this thesis an innovative restoration strategy isproposed using Doubly-Fed Induction Generator-based wind farms. The strategyinvolves retention of charge in the DC bus following a blackout, thereby avoidingthe need for energy storage, and ‘Hot-Swapping’ between direct flux control modeand conventional grid-connected mode, which does not require resetting of anycontroller dynamic states. An autonomous synchronization mechanism enabled byremote synchrophasors is also proposed. In this black-start strategy a wind farmand a VSC-HVDC connected to a network unaffected by blackout, conduct line andtransformer charging and load pickup for two separate parts of a blacked out area.The proposed ‘Hot-Swapping’ and synchronization approach are applied to connectthe two parts of the grid and switch the wind farm to grid connected mode ofoperation. This approach is verified using the aforementioned hybrid co-simulationplatform for a test system. One shortcoming of DC bus charge retention method isthat the DC bus capacitors gradually discharge and hence, the restoration processhas to begin within a reasonable time frame. In the last part of this thesis it isshown that a DFIG-based wind farm operating in isolated flux control mode, cankeep its DC-bus charged even with an open terminal.
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Table of Contents
List of Figures vi
List of Tables x
List of Symbols xi
Acknowledgments xiii
Chapter 1Introduction 11.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.2 General approach for power system restoration . . . . . . . . . . . . 3
1.2.1 Bottom-up approach . . . . . . . . . . . . . . . . . . . . . . 41.2.2 Top-down approach . . . . . . . . . . . . . . . . . . . . . . . 51.2.3 Combination approach . . . . . . . . . . . . . . . . . . . . . 5
1.3 Role of HVDC links in system restoration . . . . . . . . . . . . . . 61.4 Novel DFIG-based wind farm-assisted power system restoration
method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71.5 New hybrid simulation platform for power system restoration studies 8
Chapter 2VSC-HVDC link and its control scheme 102.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102.2 Comparison between VSC and LCC technologies . . . . . . . . . . . 112.3 Overall structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . 122.4 VSC: The building block . . . . . . . . . . . . . . . . . . . . . . . . 13
2.4.1 Ideal VSC . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132.4.2 VSC topologies . . . . . . . . . . . . . . . . . . . . . . . . . 172.4.3 Two-level VSC . . . . . . . . . . . . . . . . . . . . . . . . . 22
2.5 VSC controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
iv
2.5.1 Control of real and reactive power . . . . . . . . . . . . . . . 242.5.1.1 Design and implementation of control . . . . . . . 252.5.1.2 Current control in rotating frame . . . . . . . . . . 26
2.5.2 Phase-locked loop . . . . . . . . . . . . . . . . . . . . . . . . 292.5.3 Control of DC-side voltage . . . . . . . . . . . . . . . . . . . 312.5.4 Control of AC-side voltage . . . . . . . . . . . . . . . . . . . 33
2.6 Voltage/frequency control in islanded mode . . . . . . . . . . . . . 342.7 Summary and conclusion . . . . . . . . . . . . . . . . . . . . . . . . 35
Chapter 3DFIG-based wind farms and their control scheme 373.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 373.2 DFIG-based wind energy system . . . . . . . . . . . . . . . . . . . . 39
3.2.1 Wind turbine model and characteristics . . . . . . . . . . . . 403.2.2 Doubly-fed induction generator model . . . . . . . . . . . . 423.2.3 Pitch control . . . . . . . . . . . . . . . . . . . . . . . . . . 44
3.3 Control strategy of DFIGs . . . . . . . . . . . . . . . . . . . . . . . 443.3.1 Grid-connected mode of control . . . . . . . . . . . . . . . . 45
3.3.1.1 RSC control . . . . . . . . . . . . . . . . . . . . . . 453.3.1.2 GSC control . . . . . . . . . . . . . . . . . . . . . . 47
3.3.2 Isolated mode of control . . . . . . . . . . . . . . . . . . . . 483.3.2.1 RSC control . . . . . . . . . . . . . . . . . . . . . . 483.3.2.2 GSC control . . . . . . . . . . . . . . . . . . . . . . 50
3.4 Summary and conclusion . . . . . . . . . . . . . . . . . . . . . . . . 51
Chapter 4Novel hybrid simulation platform in VSC-HVDC-assisted power
system restoration studies 524.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 524.2 Need for hybrid co-simulation . . . . . . . . . . . . . . . . . . . . . 534.3 Hybrid simulation architecture . . . . . . . . . . . . . . . . . . . . . 54
4.3.1 PSSE-side changes . . . . . . . . . . . . . . . . . . . . . . . 564.3.2 PSCAD-side changes . . . . . . . . . . . . . . . . . . . . . . 57
4.4 Simulation studies: hybrid vs non-hybrid . . . . . . . . . . . . . . . 594.4.1 VSC-HVDC model and controls . . . . . . . . . . . . . . . . 594.4.2 Non-hybrid model . . . . . . . . . . . . . . . . . . . . . . . . 604.4.3 Hybrid model . . . . . . . . . . . . . . . . . . . . . . . . . . 60
4.5 Simulation results . . . . . . . . . . . . . . . . . . . . . . . . . . . . 604.5.1 System restoration: hybrid vs non-hybrid . . . . . . . . . . . 624.5.2 Additional load pick up: hybrid simulation . . . . . . . . . . 64
v
4.6 Summary and conclusion . . . . . . . . . . . . . . . . . . . . . . . . 65
Chapter 5Novel power system restoration strategy using DFIG-based wind
farms and VSC-HVDC links 675.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 675.2 Proposed black-start process using wind farms . . . . . . . . . . . . 68
5.2.1 Step I: DC-bus pre-charging controls . . . . . . . . . . . . . 695.2.2 Step II: Line charging and load pickup . . . . . . . . . . . . 715.2.3 Step III: PMU-enabled autonomous synchronization . . . . . 725.2.4 Step IV: Hot-swapping . . . . . . . . . . . . . . . . . . . . . 73
5.2.4.1 Notable points regarding ‘hot-swapping’ . . . . . . 745.3 VSC-HVDC controls for black-start . . . . . . . . . . . . . . . . . . 745.4 Simulation study . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75
5.4.1 System configuration . . . . . . . . . . . . . . . . . . . . . . 755.4.2 Cold load effect . . . . . . . . . . . . . . . . . . . . . . . . . 755.4.3 Simulation results . . . . . . . . . . . . . . . . . . . . . . . . 76
5.5 A self-supporting DC-bus scheme for DFIG-based wind farms . . . 835.5.1 Proposed approach . . . . . . . . . . . . . . . . . . . . . . . 845.5.2 Case study and results . . . . . . . . . . . . . . . . . . . . . 86
5.6 Summary and conclusion . . . . . . . . . . . . . . . . . . . . . . . . 87
Appendix ASpace phasor and dq reference frame 89A.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89A.2 Space phasor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89
A.2.1 dq-frame representation of a space phasor . . . . . . . . . . . 90
Appendix BLine-commutated HVDC 92B.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92B.2 Overview on LCC-HVDC . . . . . . . . . . . . . . . . . . . . . . . 92
Bibliography 94
vi
List of Figures
1.1 Sequence of events during a power system blackout. . . . . . . . . . 3
2.1 AC and DC transmission cost by length. . . . . . . . . . . . . . . . 112.2 Configuration VSC-HVDC system with its control structure. . . . . 142.3 Configuration of a bipolar VSC-HVDC system with metallic return. 152.4 Ideal VSC interfacing DC and AC systems . . . . . . . . . . . . . . 152.5 VSC interfacing DC and AC systems through LC filters . . . . . . . 182.6 Schematic of a half-bridge, single-phase, two-level VSC . . . . . . . 192.7 Schematic of a H-bridge . . . . . . . . . . . . . . . . . . . . . . . . 202.8 Schematic of a three phase three-level VSC . . . . . . . . . . . . . . 202.9 Schematic showing one leg of a three-phase MMC . . . . . . . . . . 212.10 Simplified schematic of the two-level three phase VSC . . . . . . . . 222.11 Signal flow diagram of PWM strategy . . . . . . . . . . . . . . . . . 232.12 Waveforms of the modulating signal (m), carrier signal, and AC-side
terminal voltage, based on the SPWM switching strategy . . . . . . 232.13 Block diagram of the control plant describing the dynamics of the
AC side current in a general dq frame . . . . . . . . . . . . . . . . . 272.14 Block diagram of the current-control scheme for control plant . . . . 282.15 A space phasor and dq rotating frame . . . . . . . . . . . . . . . . . 292.16 Block diagram of a PLL. . . . . . . . . . . . . . . . . . . . . . . . . 302.17 Control block diagram of the PLL. . . . . . . . . . . . . . . . . . . 312.18 Block diagram of the control plant describing DC voltage control. . 332.19 Block diagram illustrating the process of DC voltage control . . . . 342.20 Block diagram illustrating the process of AC voltage regulation at
the coupling point . . . . . . . . . . . . . . . . . . . . . . . . . . . . 342.21 Block diagram of voltage/frequency control of VSC in islanded mode. 36
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3.1 (a) Schematic of constant-speed wind power system. Schematic ofvariable-speed wind power system based on (b) wound rotor induc-tion generator without power electronic converters, (c) doubly-fedinduction generator and power electronic converter, (d) synchronousand asynchronous generator and full power electronics conversion. . 38
3.2 Typical performance-coefficient versus tip-speed-ratio characteristiccurve of a wind turbine. . . . . . . . . . . . . . . . . . . . . . . . . 41
3.3 Block diagram of turbine pitch control (Active only when ωr crossesa threshold). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
3.4 Grid-connected DFIG-based wind farm control scheme. . . . . . . . 463.5 Isolated DFIG-based wind farm control scheme. . . . . . . . . . . . 49
4.1 (a) Proposed hybrid simulation architecture. The updation of datafrom PSCAD/EMTDC to PSSE and vice-versa takes place at asampling rate, which is equal to the integration time step that islarger among the two platforms. ETRAN library components: (b)‘ETRANPlus-Com,’ (c) ‘AutoLaunch,’ (d) ‘chan-import.’ . . . . . . 55
4.2 VSC-HVDC controls for the positive pole of the inverter. . . . . . . 604.3 Hybrid simulation setup for a 8-machine, 31-bus 4-area power system
with a bipolar VSC-HVDC link with metallic return connecting areas#3 and #4. Individual circuit breakers and the time of operationof those are shown. A portion of area #3 is modeled as detailed3-phase network in EMTDC/PSCAD. The rest of the model is builtin phasor domain in PSSE software. . . . . . . . . . . . . . . . . . . 61
4.4 Dynamic response during system restoration from: (a),(c),(e) non-hybrid and, (b),(d)(f) hybrid simulation platforms. . . . . . . . . . 63
4.5 (a)-(b) Comparison of dynamic behavior of frequency at bus 6interfacing the detailed and the equivalent/phasor model for non-hybrid and hybrid simulations , and (c) a zoomed view of thefrequency comparing responses from non-hybrid (black trace), andhybrid (grey trace) simulations. . . . . . . . . . . . . . . . . . . . . 63
4.6 Hybrid simulation: dynamic response for simulating additional loadpickup in 22-bus test system shown in Fig. 4.3(a). . . . . . . . . . . 64
5.1 DFIG control scheme for black-start: ‘Hot-Swapping’ and autonomoussynchronization are shown. . . . . . . . . . . . . . . . . . . . . . . 69
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5.2 The DFIG-based wind farm is disconnected from the grid at t = 7.0sfollowed by the application of DC-bus pre-charging control. (a)Rotor power input equivalent to power flow from GSC to RSC. (b)DC-link voltage: zoomed views show the instant of stopping GSCand RSC, respectively. . . . . . . . . . . . . . . . . . . . . . . . . . 70
5.3 DC link voltage magnitude when the DFIG-based wind farm operatesin isolated mode with open terminal. . . . . . . . . . . . . . . . . . 71
5.4 Proposed PMU-enabled Autonomous Synchronization. . . . . . . . 735.5 Test system configuration consisting of a 3-area, 6-machine, 27-bus
network including a DFIG-based wind farm connected to a remotegrid through a point-to-point bi-polar VSC-HVDC link. A portionof the 3-area system is under blackout while the remote grid ishealthy. Light grey: model in PSSE. Dark grey: model in PSCAD. . 74
5.6 (a) Wind speed profile. (b) Variation in wind turbine pitch angle. . 765.7 Build up of (a) magnetizing current and (b) terminal voltage of
DFIG-based wind farm during line charging and simultaneous remoteload pickup. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77
5.8 (a) DC-link voltage of the DFIG-based wind farm and (b) the powerconsumed by the remote loads at bus 8 picked up by the wind farm. 77
5.9 Comparison of voltage build up in phase a at (a) bus 8 from the windfarm and (b) at bus 7 from VSC-HVDC. (c) Overlapping zoomedview. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78
5.10 Power flow: (a) from 20-bus system to bus 6, (b) out of positivepole VSC station, (c) out of generator G2, (d) from bus 153 to bus3006, (e) from bus 152 to bus 3004, and (f) from bus 205 to bus 154. 80
5.11 Dynamic performance while connecting the breaker BR4 withoutproposed synchronization process: (a) Phase difference betweenvoltages in both sides of breaker BR4. (b) DC-link voltage of DFIG.(c) GSC modulating signals. . . . . . . . . . . . . . . . . . . . . . . 80
5.12 Dynamic performance while connecting the breaker BR4 followingproposed synchronization process: (a) Phase difference betweenvoltages and (b) Frequency from both sides of breaker BR4. . . . . 81
5.13 Frequency of two sides of breaker BR4 (a) before breaker closureand (b) after breaker closure. . . . . . . . . . . . . . . . . . . . . . 81
5.14 Phase a voltages at two sides of breaker BR4 during auto-synchronization.v8a is instantaneous voltage at bus 8 and v7a is instantaneous voltageat bus 7. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82
5.15 (a) DFIG GSC d-axis current and (b) DC-link voltage during closureof BR4 at t = 14.0s and Hot-Swapping. . . . . . . . . . . . . . . . . 82
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5.16 DFIG RSC currents in d and q reference frames during closure ofBR4 at t = 14.0s and Hot-Swapping. . . . . . . . . . . . . . . . . . 83
5.17 (a) Test system configuration consisting of DFIG-based wind farmand its controls, step up transformers, grid, transmission line andremote loads. (b) Flow chart showing the sequence of events in casestudy. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84
5.18 (a) Real and reactive power fed to remote loads. (b) Power outputof the DFIG-based wind farm. (c) DC-bus voltage. (d) DFIG-basedwind farm terminal rms voltage. . . . . . . . . . . . . . . . . . . . . 85
5.19 (a) Rotor power input equivalent to power flow from RSC to GSC,and (b) DC-link voltage, when the DFIG-based wind farm is dis-connected from the grid at t = 7.0s followed by the application ofDC-bus charge retaining process. (c) DC-link voltage between 8sand 24s. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85
5.20 DFIG-based wind farm’s instantaneous terminal voltage (one phase)when operating in: (a) grid-connected mode, (b) isolated modewith open terminal, (c) isolated mode serving 220MW and 45MVArremote load, and (d) isolated mode supplying an additional 90MWand 30MVAr remote load. . . . . . . . . . . . . . . . . . . . . . . . 87
B.1 Schematic of a Graetz bridge. . . . . . . . . . . . . . . . . . . . . . 93
x
List of Tables
2.1 A comparison between VSC and LCC . . . . . . . . . . . . . . . . . 13
xi
List of Symbols
ρ air mass density
r turbine radius
Vw wind speed
Cp performance coefficient
λ tip-speed ratio
λopt optimal tip-speed ratio
β turbine pitch angle
A turbine swept area
Cf blade design constant
ωtur rotational speed of turbine blades
ωturopt optimal rotational speed of turbine blades
Pturmax maximum power extracted by turbine
Cpmax maximum performance coefficient
Tturmax maximum turbine torque
ωo rotational speed of turbine blades
fo stator current frequency
fr rotor frequency
s machine slip
ωr rotor rotational speed
p number of pole pairs
λs stator flux linkage
xii
Lm mutual inductance
Ls stator leakage inductance
Lr rotor leakage inductance
Rs stator resistance
Rr rotor resistance
Pe electromagnetic power
Te electromagnetic torque
ims magnetizing current
ids d-axis stator current
iqs q-axis stator current
iαs α-axis stator current
iβs β-axis stator current
idr d-axis rotor current
iqr q-axis rotor current
λds d-axis stator flux
λqs q-axis stator flux
λdr d-axis rotor flux
λqr q-axis rotor flux
λαs α-axis stator flux
λβs β-axis stator flux
Jωt inertia constant of rotating mass
Tωt input mechanical torque applied to generator
vαt α-axis PCC voltage
vβt β-axis PCC voltage
θt angle of PCC voltage
θr rotor angle
θslip generator slip angle
Rfr rotor-side converter filter resistance
Lfr rotor-side converter filter inductance
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Acknowledgments
First and foremost, I would like to thank my advisor Dr. Nilanjan Ray Chaudhurifor giving me the opportunity to be a member of his research group. I greatlyappreciate his guidance, support, and patience.
In addition, I would also like to thank Dr. Mehdi Kiani for accepting to be inmy thesis committee and taking on the responsibility.
Finally, I would like to thank my family. Without their love and support thiswork would not have been possible.
This work is partially supported by NSF under grant award # 1656983. Anyopinions, findings, and conclusions or recommendations expressed in this work arethose of the author and do not necessarily reflect the views of the NSF.
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Chapter 1 |
Introduction
1.1 Introduction
Modern power grid is a very large and interconnected system that spreads over
countries and continents. System planners derive an operating envelop of the
grid by performing rigorous planning studies that take into account all credible
contingencies. Grid operators tend to remain within this envelop to ensure a reliable
operation. However, under certain extremely rare circumstances, faults in such a
large-scale system can lead to a cascaded outage, which in turn can expand rapidly
and cause massive blackouts. History of power grid blackouts have shown that
cascaded failures of such a large system has enormous impact on the socio-economic
aspects of a nation. Although infrequent, the cost of blackouts in the USA, e.g.
the Western Electricity Coordinating Council (WECC) blackout in 1996, the 2003
blackout in the Eastern Interconnection, and the massive blackouts that took place
in 2012 in India run into billions of dollars. In this context, there are two key
aspects of research that are being pursued: (a) research on system monitoring and
control that can prevent the spread of such blackouts, and (b) research on system
restoration that can reduce the downtime of a power grid when such a blackout
takes place. The topic of system restoration is the subject matter of this thesis.
High voltage DC (HVDC) links, especially Voltage Sourced Converter (VSC)-
HVDC, when interconnects two asynchronous AC systems - can act as a ‘firewall’
against the propagation of blackouts. This implies that the blackout taking place
in one AC-area cannot propagate into the other. During the North-East blackout
of 2003, the 330-MW VSC-HVDC link across Long Island Sound, also known as
1
Cross-Sound Cable (CSC), was started up under an emergency order from the US
Department of Energy [1] to facilitate the black-start process.
System planners designate certain generating units as ‘black-start’ units, which
are used during the early phase of the restoration process. Although a growing
portion of generation in modern power grid comes from wind farms, so far only
conventional generators have been considered as black-start units for power system
restoration [2]. In this thesis, it is shown that a Doubly-Fed Induction Generator
(DFIG)-based wind farm can be effectively used for such purpose by means of a
seamless control transition and autonomous synchronization approach without any
need for energy storage systems.
Application of VSC-HVDC links in power system restoration has been demon-
strated in literature through detailed Electromagnetic Transient (EMT)-type models
of very small-scale systems. However, studying restoration of large power systems
using such detailed models is computationally prohibitive. In this thesis, a hybrid
simulation platform is proposed for such studies in which a significant portion of
the system, for which developing a detailed three phase model is not necessary, is
modelled in a phasor framework and is co-simulated with a detailed EMT-type
model of a smaller portion containing DFIG and VSC-HVDC link.
The following are the salient contributions of this thesis -
1. A novel method of black-start using DFIG-based wind farms and VSC-HVDC
systems is proposed, and
2. A hybrid simulation platform for VSC-HVDC-assisted power system restora-
tion study is proposed.
The outline of the thesis is as follows - This chapter briefly discusses different
considerations in power system restoration and general approaches for black-start.
The history and advantages of HVDC-assisted black-start is also briefly discussed
in this chapter. Since one of the main topics in this thesis is VSC-HVDC-assisted
restoration, chapter 2 describes the structure and control scheme of voltage sourced
converters (VSCs), which are used in point-to-point VSC-HVDC systems. Chapter
3 describes the structure, characteristics and controls of doubly-fed induction
generator (DFIG)-based wind energy systems. Using the background information
from chapter 2 and chapter 3, chapter 5 proposes a novel method of power system
restoration using VSC-HVDC systems and DFIG-based wind farms simultaneously.
The effectiveness of this restoration method will be demonstrated by using a hybrid
2
Initiating
events
System
seperation
Formation of
islands
Load/
generator
imbalance in
islands
Islands
blackout
Begin
restoration
process
Figure 1.1. Sequence of events during a power system blackout.
co-simulation platform. This proposed platform, which is a useful tool in large-scale
restoration studies will be discussed in chapter 4.
1.2 General approach for power system restoration
There are several phenomena which could cause blackout in power systems including
system voltage collapse, large deviations in frequency and large imbalance in real
power demand and supply. Severe weather conditions such as hurricanes can also
result in blackouts by causing faults and damages in transmission system. Fig. 1.1
shows the common sequence of events resulting in a blackout. As it can be seen
from Fig. 1.1, any of the aforementioned events can cause the power grid to divide
into several separate so called ‘islands’ with supply/demand imbalance which results
in blackouts in each of these islands.
The methods and considerations for system restoration depend on several factors
including whether the blackout has happened on a local or system-wide scale and
also whether there is access to external support or not. Other factors that should
be brought into consideration include the availability of generating units and
equipments, restoration time, voltage control, transient overvoltages and dynamic
issues [1, 3]. Moreover, protection issues usually arise during restoration due to
high or low voltages, large rate of changes in frequency and excessive unbalance
in voltage or current, which need to be considered [4]. The final objective of
power system restoration is to bring the system to normal operating condition
with a fast and secure method, minimizing costs, losses and outage time. Hence,
3
power system restoration is a multi-variable, multi-constraint, and multi-objective
optimization problem [5]. There are other constraints such as stability of system
during restoration which needs to be considered. This means that one should
make sure that the voltage and frequency are within the rated range during the
restoration process, and that these variables have small enough deviations as
each load is picked up. Several methods have been used to meet the objectives
and constraints of restoration problem and provide a solution such as case-based
reasoning [6]. Heuristic algorithms such as genetic algorithms [7] and fuzzy logic [8]
have also been applied to system restoration problem.
In case of a blackout, the black-start units start charging transmission lines
and transformers so that the non-black-start units could also start up and connect
to the grid. Based on North American Electric Reliability Corporation (NERC)
definition, black-start units (BSU) are generators with the ability to start without
any outer support from the grid like hydroelectric units [9]. Gas turbine-based
plants can also be profitably used in system restoration as black-start units [10].
Simultaneously, cold loads could be picked up by these generating units based on
related considerations including generation and transmission capacities, the priority
of loads to be picked up and stability considerations. There are general approaches
for system black-start which are employed based on the scale of blackout, and
availability of resources and outer support. These general approaches are briefly
described in the following subsections.
1.2.1 Bottom-up approach
This is the only method, which can be used in case of a full system shutdown with
no outside support available. In this method several islands are formed within the
large system where each island includes BSUs.
After starting up each BSU, transmission lines are charged and loads are picked
up in an area around that unit to form an island. These islands are expanded by
charging more lines and picking up more loads. After the restoration process has
been completed for all of these islands within the system, they are synchronized
and connected to complete the whole system black-start process. Naturally, the
transmission paths and loads are chosen in the optimal way in each island. This
method is referred to as multi-island method [11].
4
Another common approach is to have a core island rather than multiple ones [11].
In this case a larger island with more generating capacity is formed and expanded
gradually until the whole system is restored. It results is a shorter restoration time
besides the fact that it reduces the control effort since there is a single core island
instead of multiple ones. However, this method has several disadvantages. In case
of a failure in core island the black-start process should be restarted. Furthermore,
restoration of critical loads and generation located far from core island will be
delayed, which is undesirable. On the other hand in the multi-island method, if a
failure happens in one of the islands, restoration process can still proceed in others.
However, slower overall restoration and small inertia in islands, which has adverse
effect on stability are the main demerits of multi-island method.
1.2.2 Top-down approach
This approach is dependent on outer support and hence is only applicable in cases
when there is an outer source available to be used for black-start of collapsed
region. In this method a backbone transmission system is restored with support
from outside assistance to restore critical generation, substations and loads [11].
By starting more generation and picking up more loads the black-start process
proceeds. This method has the advantages of restoring critical auxiliary equipments
for generating units in a short time and no need for synchronization since we do
not have multiple islands. However, it is highly dependent on neighboring system’s
supplying capacity and transmission constraints which can limit the amount of
transmittable power from outer system.
1.2.3 Combination approach
In this method a combination of bottom-up and top-down approaches is used
simultaneously [11]. A backbone transmission system is formed with the support
of outer system and generation islands are built and expanded. It results in a
fast black-start process, which allows restoration of multiple areas of a system in
parallel. However, as it could be easily understood, it includes demerits of other
approaches including dependency on neighboring system supplying capacity, more
control efforts due to formation of multiple islands and synchronization needed
before merging them.
5
1.3 Role of HVDC links in system restoration
High-Voltage DC (HVDC) transmission systems were developed primarily as the
more economical and feasible option for bulk power transmission in long distances.
The excessive line charging current in AC transmission lines in such distances makes
them unsuitable for long distance bulk power transmission; while, there is no such
limitation for underground DC lines [12]. However, since the power grid is still
operating dominantly on AC voltage, the HVDC links need AC/DC converters to
be connected to the rest of the grid. The two common technologies used in AC/DC
conversion in power system are the line-commutated converter (LCC) and the
voltage-sourced converter (VSC) technologies (The structure and control scheme of
these converters will be discussed in detail in chapter 2).
The first commercial HVDC transmission system was built in 1954 in Europe,
connecting Gotland in Baltic sea to mainland Sweden and has been expanding in
capacity since then [13]. The converter stations in this system use LCC technology
which was developed earlier than the VSC technology. Due to its earlier development,
LCC is now a mature technology compared to VSC, which was developed in late
90s and is still a developing technology [14]. Because of the same reason, only a
small portion (<10GW) of installed HVDC worldwide, which is over 100GW and
additional 200GW planned to be added by china [15], is of VSC technology [16].
Although LCC-HVDC systems can be used in black-start process depending on
the availability of other equipments, some of the unique features of VSC-HVDC
systems make them a preferred candidate for restoration purpose. LCC-HVDC
requires a source of AC voltage for operation. As a result, the LCC-HVDC systems
need synchronous condensers to be able to be used for black-start operation. During
restoration, the AC grid behaves as a ’weak’ system, which results in issues including
high dynamic over voltage, voltage instability, large voltage flicker, and harmonic
instability causing challenges for LCC-HVDC systems [16]. Some of these problems
can be solved by connecting synchronous condensers or static VAr compensators
(SVC) at the converter bus. On the contrary, the VSC-HVDC systems do not
need a stiff AC voltage source for operation due to their self-commutation property.
VSC-HVDC systems can independently control real and reactive power while LCC-
HVDC does not have any control over the consumption of reactive power [14].
Furthermore, VSC-HVDC can impose desired frequency and voltage magnitude on
6
a blacked-out AC grid connected to it and does not need synchronous condensers
for restoration purpose. Besides these advantages, one of the main applications
of HVDC connections is in power transmission from remote resources such as
hydroelectric units. As mentioned earlier, hydroelectric plants are one of the
primary choices as black-start units. Hence, in case of a blackout, the favorable
black-start capabilities of VSC-HVDC systems can be utilized to restore the system
using hydroelectric sources [17].
In case of a blackout, a VSC-HVDC link, which is connected between two
asynchronous networks can act as a "firewall" and prevent the propagation of the
blackout to the system connected to its other end. When a blackout happens in
the AC system connected to one end of HVDC link, energy storage systems ensure
the necessary equipment like control and protection continue to operate for some
time. Later, the healthy system at the other end of the HVDC link can be used to
energize the DC link and charge the capacitors at the local station. This station
can then start operating in black-start mode to control AC voltage and frequency
in the blacked out system and initiate black-start process by transmission line
charging and cold load pickup. Details of principle of operation of VSC HVDC
and its controls are presented in chapter 2, and chapter 5 describes its black-start
features.
1.4 Novel DFIG-based wind farm-assisted power
system restoration method
The generation mix in the modern power grid is undergoing a significant change
as more renewable energy penetration, especially from wind energy takes place.
However, thus far, regulators have refrained from considering renewable energy
resources as resources in the system restoration process. In literature, several works
have studied restoration of microgrids using renewable sources, which is different
compared to transmission system restoration including [18–20]. The AC voltage
is first established by solar PV, battery storage, or diesel generation before the
wind resource is connected. This disqualifies the wind sources described in these
papers as aforementioned black-start unit per NERC definition [9] since they lack
the ability to be started without assistance from the system and energize a dead
7
bus. Only a few papers [21–25] have proposed wind units for transmission system
restoration where [21], [22] presented very preliminary results; [23] utilized a diesel
generator before connecting the wind unit; [24] needs battery energy storage in the
DC link of the wind unit; and [25] is focused on the static aspects of restoration.
In this thesis a novel restoration strategy is proposed using DFIG-based wind
farms without any conflict with their normal operation or any major deviation
from current widely manufactured and used DIFG-based wind turbine systems. In
this proposed strategy, there is no need for energy storage equipments and hence it
complies with the NERC definition [9] of black-start unit.
Wind farms can generally be operated when connected to power grid or when
feeding isolated loads. There are different control schemes for the operation in these
two modes. Chapter 3 describes two widely-known control schemes for DFIG-based
wind farms in grid-connected and isolated modes of operation. In the proposed
strategy, one of the two control schemes is used to start up a DFIG-based wind
farm in isolated mode. In this mode the wind farm can energize transmission lines
and pick up local or remote loads, while the rest of the system is restored by other
sources. An ‘autonomous synchronization’ method, will be proposed in chapter
5, which can be utilized to connect the wind farm feeding the isolated load, to
the rest of the grid, and switch its control structure to grid-connected mode. The
details of this restoration approach are described in chapter 5 and nonlinear hybrid
simulation studies are presented to validate its performance.
1.5 New hybrid simulation platform for power sys-
tem restoration studies
The restoration process of a power grid involves phenomena that can be associated
with a wide range of time-constants. Phenomena like transformer inrush and
long line switching currents during this process require Electro-Magnetic Transient
(EMT)-type simulation. The EMT-type models are detailed three-phase models
and hence, running this type of simulations is significantly time consuming. Due
to this fact, running this type of three-phase simulation for large-scale systems
is computationally prohibitive. However, voltage, angle and stability issues can
be represented by phasor models in transient stability (TS) simulation, which are
8
computationally much faster than EMT-type models.
In this thesis, the focus is on restoration assisted by DFIGs and VSC-HVDC.
The tasks performed by a VSC-HVDC link during system restoration include
transformer energization, line energization, generator synchronization, system
inertia and frequency control, cold load pickup, etc. DFIG-based wind farms will also
be used for transformer and line charging, load pickup, and synchronization. The
issues facing these operations include voltage fluctuations, low system damping in
absence of loads in the system, large inrush current during transformer energization,
resonance, and so on. To simulate these phenomena, an EMT-type model is needed.
However, as mentioned, the use of this type of model for simulating a large-scale
system is not feasible. To solve this problem, a hybrid co-simulation platform is
proposed in chapter 4 as a useful tool for large-scale system restoration studies
involving DFIG-based wind farms and VSC-HVDC links. In this platform, a portion
of the system including DFIG and VSC-HVDC link and their surroundings are
modeled in a three-phase EMT environment in EMTDC/PSCAD [26], while the
rest of the system including loads, generators and transmission lines is represented
by a phasor model in PSSE [27]. The exchange of data between the two models
is achieved via ETRAN-PLUS [28] which provides an interface between them. In
chapter 4, details of this hybrid co-simulation platform is presented. Finally, in
chapter 5 the effectiveness of the proposed restoration method is validated using this
platform for a reasonably large system consisting of multiple areas, a DFIG-based
wind farm and a VSC-HVDC link.
9
Chapter 2 |
VSC-HVDC link and its con-trol scheme
2.1 Introduction
Chapter 1 provided a background on the challenges of power system restoration and
general approaches of black-start. As mentioned, VSC-HVDC links can act as a
firewall to restrict the propagation of cascaded failures. Moreover, VSC-HVDC can
significantly improve system restoration. This chapter discusses the fundamentals
of operation and control of VSC-HVDC systems.
The main motivation for developing high voltage DC transmission lines was
their cost effectiveness in transmitting bulk power over long distances. Although
the installation costs are higher for the HVDC transmission system (because of
the needed converter stations and associated infrastructure), they become a more
economical option than AC lines beyond a certain distance. Figure 2.1 shows
variation in cost for an AC transmission compared to an HVDC transmission with
transmission distance. As it is shown in Fig 2.1, for over a certain distance, called
"break-even distance", HVDC transmission provides a lower cost. The break-even
distance is about 700 to 900 Km for overhead HVDC lines. For underground
or subsea cable transmission, this distance is much shorter (typically about 50
Km) [16]. However, this is not the only reason for using HVDC transmission
lines. For underground transmission, the high charging current in medium and long
distance AC cables disqualifies them for such transmission purposes. Moreover, the
losses in DC transmission are lower compared to their AC counterpart. [29].
10
co
st
co
st
Transmission distanceTransmission distance
AC lineAC line
DC lineDC line
Break-even distanceBreak-even distance
Figure 2.1. AC and DC transmission cost by length.
Since the power grid is dominantly AC, AC/DC converters are needed to interface
HVDC transmission lines with the AC grid. There are three types of devices which
have been used in converters in HVDC transmission systems. Mercury arc valves
where used in the first LCC-HVDC system connecting Gotland to mainland Sweden
in 1954. They were in use until 1970, when thyristors started to be used in HVDC
converters [30]. In the late 90s, insulated gate bipolar transistors (IGBT) became
commercially available for high power ratings. IGBTs where later used to develop
the voltage sourced converter (VSC)-based HVDC systems. The LCC-HVDC and
VSC-HVDC, which are the two technologies currently in use in HVDC transmission
are compared briefly in the following section.
2.2 Comparison between VSC and LCC technolo-
gies
LCC was developed several decades earlier than VSC and hence is a more mature
technology widely used in HVDC systems around the world. As mentioned earlier,
LCC converter stations use thyristors as switching devices which are turned on by
gate pulses when they are forward biased. However, they can only be turned off
11
when the commutating AC voltage becomes negative. Usually large reactors are
connected to the DC-side of these converters to smooth the voltage and current
ripples. The flow of current in the DC link is unidirectional and hence, the direction
of power flow is reversed by changing the DC voltage polarity. These type of
converters consume large amounts of reactive power. Usually large capacitor banks
are connected on the AC-side to supply the reactive power needed for converters.
Due to the requirement of large capacitor banks and harmonic filters, the footprint
of LCC-HVDC converters is large [16]. The basics of LCC-HVDC systems is briefly
described in Appendix B.
Unlike LCC, VSC is still a developing technology. This type of converters
typically use IGBTs with anti-parallel diodes. IGBTs offer both controlled turn-on
and turn-off capability. Both the magnitude and phase angle of the AC voltage can
be controlled by VSCs, which enables independent control of active and reactive
power exchange with the AC system at both ends. VSC-HVDC systems require
significantly less filtering and hence, the footprint of this type of stations is much
less than LCC. The polarity of DC voltage is fixed in VSC-HVDC links and the
direction of power flow can be changed by reversing the direction of current flow.
The LCC systems rely on AC system voltage for turning off the thyristors. This
means that they face serious challenges when connected to a weak grid. There
is no such restriction for a VSC HVDC link which can work even with weak or
isolated AC systems and offer black start capability. Some of the differences between
VSC-HVDC links and LCC-HVDC links are shown in Table 2.2. VSCs are discussed
in detail later in this chapter.
2.3 Overall structure
Figure 4.2 shows the structure of a VSC-HVDC system with the control scheme
of its converters. The VSCs are built using IGBTs and anti-parallel diodes. The
DC/AC voltage conversion is achieved by controlled turn on and turn off of these
IGBTs. The VSC can independently control the active and reactive power exchange
with the AC system by regulating the magnitude and phase angle of its AC terminal
voltage. The real power flow can be reversed by altering the DC current direction,
while keeping the DC-link voltage polarity the same. In a VSC-HVDC system, one
converter station controls the DC link voltage, while the other usually sets the
12
Table 2.1. A comparison between VSC and LCCLCC V SC
Thyristor base technology IGBT base technologyConstant current direction Current direction changes
with powerTurned on by a gate pulse Both turn on and off isbut rely on external circuit carried out without the
for its turn off help of an external circuitRequires stronger AC systems Operate well in weak
for excellent performance AC systemsRequires additional equipment Has black-start
for black-start operation capabilityReversal of power is done Reversal of power is doneby reversing the voltage by reversing the current
polarity flow direction
active power reference. Furthermore, each converter can independently control the
AC side voltage or reactive power at either end. The VSC-HVDC system shown in
Fig. 4.2 is a monopolar configuration. It is also possible to have a bipolar structure
in which there are two VSC stations at each end; positive pole and negative pole
station as shown in Fig. 2.3. In this case the HVDC link consists of a positive and
a negative pole cable and a metallic return.
The structure of VSCs and the details of their control scheme are the subject
matter of the following sections.
2.4 VSC: The building block
2.4.1 Ideal VSC
Consider Fig. 2.4 where a five-terminal device shown as ideal VSC operates as a
medium for energy transfer between DC and AC systems. This ideal VSC is a
system consisting of passive, memory-less and loss-less circuit elements including
ideal transformer, diode and switch. As shown in Fig. 2.4 the DC-side terminal
voltage and currents are denoted by vdc and idc, respectively. Here, a positive
current is assumed to be the current entering the DC-side port as it appears in
Fig. 2.4. The three remaining terminals identify the AC-side of the VSC and are
13
ne
ga
tiv
e p
ole
()
vKs
*0
gsc
Q=
ext
P
/ /
L L
()
iKs ()
iKs
PW
M
()
iKs ()
iKs
L L
/ /*
0gsc
Q=
*P
po
siti
ve
po
le
G2
G1
Sy
ste
m #
1S
yst
em
#2
rec
tifi
er
inv
ert
er
inve
rte
r-si
de
co
ntr
ols
rect
ifie
r-si
de
co
ntr
ols
dcr
Vdci
V
tivtrv
* gdi
i
gdi
i * gqi
igqi
i
tdi
v tqi
v
* gdi
v * gqi
v* gqr
v* gdr
v
tdr
v tqr
v
* gdr
i gdr
i gqr
i
* gqr
i
()2
* dcrv (
)2dcrv
3 2tdi
v−
3 2tdr
v−
Figure 2.2. Configuration VSC-HVDC system with its control structure.
14
G1G2
System #2
positive pole
negative pole
metallicReturn
System #1
Figure 2.3. Configuration of a bipolar VSC-HVDC system with metallic return.
DC
system
Ideal
VSC
AC
system
dcP
dci
dci
dcv0
/ 2dcv
/ 2dcv
gai
gbi
gci
gav
gbv
gcv
gP
gQ
Figure 2.4. Ideal VSC interfacing DC and AC systems
assumed to have voltages vga, vgb, and vgc with respect to a reference node indicated
in Fig. 2.4 as ‘0‘. This reference node is referred to as the DC-side midpoint of the
VSC. Typically, this is a virtual node used to simplify the analysis. The AC-side
voltages are three-phase balanced sinusoidal voltages whose magnitude and phase
angle are controllable. As indicated in Fig. 2.4, the currents iga, igb, and igc leave
the corresponding AC-side terminals of the VSC and enter the AC system.
15
Since AC side voltages are balanced sinusoidal, they can be represented as:
vga(t) = Vg(t) cos [ε(t)]
vgb(t) = Vg(t) cos[
ε(t)− 2π3
]
vgc(t) = Vg(t) cos[
ε(t)− 4π3
]
(2.1)
where, Vg(t) and ε(t) are voltage magnitude and angle of the AC side voltage
respectively. Usually ε(t) is not directly controlled, but it is related to frequency,
ω(t) by:
ε(t) = εo +
∫ t
0
ω(τ)dτ (2.2)
where, εo is the initial phase angle.
Assuming an undistorted sinusoidal Thevenin voltage for the AC grid at the
coupling point, a nonzero average energy transfer, i.e., a nonzero real-power flow,
can exist only if the VSC operates at the same frequency as that of the AC grid,
that is, if ω(t) is made equal to the power system frequency. Thus, if the power
system frequency is constant at a value ωs, then, based on (2.1) and (2.2), the
AC-side voltages assume the forms:
vga(t) = Vg(t) cos [ωst+ εo]
vgb(t) = Vg(t) cos[
ωst+ εo −2π3
]
vgb(t) = Vg(t) cos[
ωst+ εo −4π3
]
(2.3)
Due to the fact that we are assuming an ideal VSC here, the power drawn from
DC system by VSC, Pdc, is equal to the power flowing into the AC system, Pg.
This means:
vdcidc = vgaiga + vgbigb + vgcigc (2.4)
The left side of (2.4) corresponds to Pdc and the right side corresponds to Pg.
Solving (2.4) for idc we have:
idc =vgaiga + vgbigb + vgcigc
vdc(2.5)
The VSC controls result in the generation of a balanced three-phase AC-side
voltage, as shown in (2.3), whose magnitude Vg is also proportional to the DC-side
voltage vdc. This three-phase voltage generates a three phase current. These
16
voltages and currents result in a power flow, which based on (2.5) translates into a
DC-side current, idc. A constant vdc is needed for the proper operation of the ideal
VSC. This means that the DC system should exhibit a small Thevenin impedance to
the DC-side port of the ideal VSC and the AC grid should exhibit a large Thevenin
impedance to the VSC from any of the coupling nodes. These requirements are
equivalent to stating that a proper operation of the VSC requires the host DC
and AC grids to be of the voltage source and current source nature, respectively.
The ideal VSC behaves as a controllable three-phase voltage source from its AC
side, and it acts as a dependent current source from its DC port. This point will
be further discussed later in this chapter. In practice, a VSC is never directly
connected to DC and AC systems. Rather, there are DC and AC filters connected
to its DC and AC side respectively. This is because the Thevenin equivalent of
the AC system cannot be counted on to ensure the current-source nature of the
AC grid. This is also true for the DC system. Another reason is that there are
harmonics in AC side voltages of the VSC due to its structure which uses switches
to generate these voltages. These voltage harmonics can also result in large current
harmonics if the Thevenin impedance of the AC system is small corresponding to
the harmonic frequencies. These harmonics do not contribute to power transfer
and stress the VSC and possibly the AC system. Hence, some impedance should
be used between the VSC AC-side and the AC system. This impedance acts as a
buffer and ensures a small distortion in currents. Figure 2.5 shows the same VSC
system shown in Fig. 2.4 with LC filters implemented between the VSC ports and
the AC and DC systems. The capacitance C provides a low impedance path for
current harmonics and prevents them from entering the AC system. The ohmic loss
of the inductors are represented by resistance R. On the DC-side, Cdc acts as open
circuit for the DC component of idc and should present a small impedance for the
harmonics in idc. An inductance Ldc might be included to ensure that the capacitor
remains effective regardless of the impedance that the DC system exhibits to the
VSC. Similar to the AC-side filter, Rdc represents the ohmic loss of Ldc.
2.4.2 VSC topologies
VSCs are built with three general topologies, which are called two-level, three-level
and multi-level depending upon how many levels of DC-side voltage they posses.
17
DC
system
Ideal
VSC
AC
system
dcP
dci
dci
dcv
0
/2dcv
/2dcv
tai tbi tcitcvtbvtav
dc
Rdc
Lli
dc
C
DC-side
filter
RL
C
AC-side
filter
gai gbi gci
gav gbv
gcv
gP
gQ
tP tQ
Figure 2.5. VSC interfacing DC and AC systems through LC filters
18
DC
sy
ste
m
p
2dcV
2dcV
n
AC system
Figure 2.6. Schematic of a half-bridge, single-phase, two-level VSC
Half-bridge two-level VSC consists of two semiconductor switches connected to
each other as shown in Fig. 2.6. The semiconductor switches should be turned on
and off in a controlled manner to generate an AC voltage in presence of DC voltage
on the other end of VSC. The capacitors act as filters to reduce the distortion in
the DC-side voltage. This type of VSCs can also be built with four switches as
full-bridge converters. The VSC shown in Fig. 2.6 is a single phase VSC. Three
phase VSC can also be built, which consists of three half-bridge converters for the
three phases (see Fig. 2.10). Such a two-level three-phase VSC topology is the focus
of this chapter and will be discussed in detail in the next section.
We can have less harmonics in terminal voltage by using more than two levels.
For example an H-bridge, shown in Fig. 2.7, can be used to synthesize three-level
VSCs. This structure is shown in Fig. 2.8. The three H-bridges are controlled using
three modulating signals which make a balanced three-phase set of waveforms. The
H-bridges are connected in parallel from their DC ports to identify the DC port
of the composite VSC, and their AC outputs are combined by three correspond-
ing single phase transformers whose grid-side windings are connected as a wye
configuration [16,31].
Increasing the number of levels beyond three can reduce the harmonic distortions
even further. One configuration of multi-level VSC, which has come to use in recent
years is known as the modular multi-level converter (MMC) [16, 32]. In this
configuration, multiple half-bridge converters are connected in series from their AC
19
dci
dcv gv
gi
Hdcv
dci
tv
ti
Figure 2.7. Schematic of a H-bridge
H gav vgaN H Hdcv
gai gbi gci
gbv gcvvgbN vgcN
dcai dcbi dccinv
gAv gBv gCv
gCigAi gBi
dci
Figure 2.8. Schematic of a three phase three-level VSC
side terminals to generate a multi-level AC voltage waveform. The configuration of
one phase of a three phase MMC is shown in Fig. 2.9. This structure consists of
two so-called arms in each phase. In each of the arms there are n series-connected
half-bridge converters, which are each connected to a capacitor in the DC-side as
shown in Fig 2.9. Assume that the DC-side voltage, vdc, is externally supported
and each of the capacitors are charged with a voltage equal to vdc/n. The AC-side
terminal of each half-bridge converter can have 0 or vdc/n as their voltages and
hence, the voltage across each of the arms can be varied from 0 to vdc/2 in steps
equal to vdc/n. The AC-side voltage of MMC can vary in steps of vdc/n by varying
20
Half-
bridge1,1dcv
1,1dci
dcC
Half-
bridgedcC
1,2dci
1,2dcv
Half-
bridgedcC
1,dc ni
1,dc nv
1,1tv
1ti
1ti
1,2tv
1ti
1,t nv
1armv
gi
gv
armL
armL
Half-
bridgedcC
Half-
bridgedcC
Half-
bridgedcC
dcv 0
/ 2dcv
/ 2dcv4armv
4ti
4ti
4ti
4,1tv
4,2tv
4,t nv
4,1dci
4,2dci
4,dc ni
4,1dcv
4,2dcv
4,dc nv
Arm#1
Arm#2
Figure 2.9. Schematic showing one leg of a three-phase MMC
varm1 and varm2. Hence, by having a large number of half bridge converters the AC
side voltage of MMC becomes remarkably smooth. Two-level three phase VSCs,
which are the main focus of this chapter, are discussed in detail in the following
sections. The details of operation of three-level and multi-level VSCs are not
discussed here and can be found in [31,32].
21
dci
dcv
gai
gbi
gci
gcv
gbv
gav
Figure 2.10. Simplified schematic of the two-level three phase VSC
2.4.3 Two-level VSC
Figure 2.10 shows the simplified schematic of a two-level three-phase VSC circuit.
The circuit consists of three half-bridge converters, one per AC-side terminal. Each
half-bridge converter consists of two controllable semiconductor switches. These
switches are turned on and off in a complimentary manner, which means when one
switch is in ‘on‘ mode the other switch should be ‘off‘. Hence, at each switching
instant, the terminal voltage of the half-bridge converter transitions from one of
the two possible levels, −vdc/2 and vdc/2, to the other one. If this switching action
is periodic, the terminal voltage has a fundamental component, which can be made
to have the desired frequency ωo. Thus we have:
〈vga〉1 (t) = Vg(t) cos [ε(t)]
〈vgb〉1 (t) = Vg(t) cos[
ε(t)− 2π3
]
〈vgc〉1 (t) = Vg(t) cos[
ε(t)− 4π3
]
(2.6)
where, ε(t) and ωo are related as shown in (2.2).
The most frequently used switching strategy for the two-level VSC is the carrier-
based, pulse-width modulation (PWM) strategy. In this strategy, the switching
22
time
m
0
time0
1
-1
sT
Carrier
Modulating
signal0
1
S1
S4
Figure 2.11. Signal flow diagram of PWM strategy
-1
0
1
m mcarrier
time
-0.5
0
0.5
v t/v
dc
Figure 2.12. Waveforms of the modulating signal (m), carrier signal, and AC-sideterminal voltage, based on the SPWM switching strategy
instants of a constituting half-bridge converter are determined by comparing a
corresponding modulating signal, m(t), with a high frequency periodic triangular
carrier signal, as Fig. 2.11 illustrates. A special case of the PWM strategy, referred
to as the sinusoidal pulse-width modulation (SPWM) strategy, uses a sinusoidal
modulating signal. Figure 2.12 shows the typical waveforms in SPWM strategy.
In a three-phase VSC, there are three modulating signals, one per half-bridge
converter, which are compared with a common carrier signal, and they constitute
a balanced three-phase sinusoidal signal. Based on the SPWM strategy, the
fundamental components of the AC-side voltages are the amplified versions of their
23
corresponding modulating signals, as:
〈vga〉1 (t) =12vdc(t)ma(t)
〈vgb〉1 (t) =12vdc(t)mb(t)
〈vgc〉1 (t) =12vdc(t)mc(t)
(2.7)
where ma(t), mb(t) and mc(t) are the modulating signals for the three phases.
Assuming:
ma(t) = M(t) cos [ε(t)]
mb(t) = M(t) cos[
ε(t)− 2π3
]
mc(t) = M(t) cos[
ε(t)− 4π3
]
(2.8)
and replacing for ma(t), mb(t), and mc(t) from 2.8 in 2.7 we obtain:
〈vga〉1 (t) =12vdc(t)M(t) cos [ε(t)]
〈vgb〉1 (t) =12vdc(t)M(t) cos
[
ε(t)− 2π3
]
〈vgc〉1 (t) =12vdc(t)M(t) cos
[
ε(t)− 4π3
]
(2.9)
Where M(t) is the magnitude of modulating signals and an independent control
variable. Furthermore, ε(t) is calculated from ωo, which is a control variable, based
on (2.2). Hence, if the DC-side voltage is constant, the fundamental components of
the AC-side terminal voltages constitute a balanced three-phase voltage. Also, if
the magnitude and frequency of the modulating signals are constants, say, M and
ωs, respectively, then the fundamental AC-side voltages take the forms:
〈vga〉1 (t) = vg cos [ωst+ εo]
〈vgb〉1 (t) = vg cos[
ωst+ εo −2π3
]
〈vgc〉1 (t) = vg cos[
ωst+ εo −4π3
]
(2.10)
where the constant vg =12vdcM is the magnitude of the AC side voltage.
2.5 VSC controls
2.5.1 Control of real and reactive power
The control of a VSC is based on the control of real and reactive power that it
exchanges with the AC system, which are shown as Pt and Qt in Fig. 2.5. The real
24
power control can be employed for power-flow control or, indirectly, for controlling
the DC-side voltage of the VSC. Reactive power control can be directly employed
for ancillary services or, indirectly, for regulating AC voltage magnitude at the point
of common coupling (PCC). The real/reactive power can be controlled based on
voltage-mode or current-mode control strategy [33,34]. In the voltage-mode control
strategy, Pt and Qt are controlled directly by the phase angle and magnitude of
the terminal voltage of the VSC, vg, relative to those of the grid voltage vt. This
control mode is easy to implement, but it makes VSC vulnerable to the AC system
faults. Furthermore, in this control strategy power control through the control of
phase angle and magnitude is based on a steady-state relationship (model) and,
therefore, typically results in a fairly poor transient performance.
In the current-mode control strategy, Pg and Qg are controlled by the AC-side
current, ig, with reference to the AC system voltage vt. In turn, ig is regulated
through the AC side terminal voltage of the VSC, vg. The VSC is protected against
over-currents and external faults since the magnitude of it will be limited if the
magnitude of the reference current is constrained. This is the main reason for
choosing the current-mode control strategy over its voltage-mode counterpart. The
details of this control strategy are described in the following subsections.
2.5.1.1 Design and implementation of control
The VSC is best analyzed and controlled via the concept of space phasors. This
concept is described in appendix A and is used here to describe the VSC controls.
Consider the system shown in Fig. 2.5. The following equations show the
dynamics of AC-side currents of the VSC:
Ldigadt
= −Riga + vga − vta
Ldigbdt
= −Rigb + vgb − vtb
Ldigcdt
= −Rigc + vgc − vtc
(2.11)
Note that since the impedance of capacitors C in the AC-side filter shown in
Fig. 2.5 is high for the fundamental frequency, we have neglected them in writing
(2.11). Multiplying the two sides of equations in (2.11) by 23ej0, 2
3ej
2π3 and 2
3ej
4π3 ,
25
respectively and adding the resulting equations, we can obtain:
LdIgdt
= −RIg + Vg − Vt (2.12)
The over bars in this equation denote space phasors. It can be seen from 2.12
that the space phasor of AC-side currents can be controlled by the space phasor
of the VSC terminal voltage. In this case the AC system voltage phasor acts as a
disturbance input.
2.5.1.2 Current control in rotating frame
If each space phasor in (2.12) is expressed in d−q frame components (see, Appendix
A), the AC side of the system in Fig 2.5 can be expressed in d− q frame. Thus, we
can obtain:L
dIgddt
= −RIgd + LωIgq + Vgd − Vtd
LdIgqdt
= −RIgq − LωIgd + Vgq − Vtq
(2.13)
From the rotating frame concept described in appendix A we have the following
relations for real and reactive power:
P (t) = Re{
32V (t)I
∗(t)
}
Q(t) = Im{
32V (t)I
∗(t)
} (2.14)
Replacing V t and Ig in (2.14) with (Vtd + jVtq) ejρ and (Igd + jIgq) e
jρ respectively,
we have:Pt(t) =
32(VtdIgd + VtqIgq)
Qt(t) =32(−VtdIgq + VtqIgd) +Qc(t)
(2.15)
where Qc(t) is the instantaneous reactive power generated by filter capacitors. It
can be understood that by knowing the AC system voltage components Vtd and
Vtq, it is possible to control Pt and Qt by controlling the VSC AC-side current
components Igd and Igq.
Equations in (2.13) represent a two input, two output dynamic system. For
this system, Vgd and Vgq are control inputs (which are produced through switching
strategy from other control inputs), Igd and Igq are the outputs and Vtd and Vtq
are the disturbance signals. This system is shown in Fig. 2.13. Here, the SPWM
switching method mentioned in section 2.4.3 is assumed. In this case Vgd and Vgq
26
dm
qm
2dcV
gdv
gqv
1
Ls R
1
Ls R
L
L
tdv
tqv
AC current dynamics
gdi
gqi
Figure 2.13. Block diagram of the control plant describing the dynamics of the AC sidecurrent in a general dq frame
are proportional to the dq frame components of the three phase modulating signals,
md and mq.
The control purpose for the system shown in Fig. 2.13 is to keep Igd and Igq
at respective reference values, I∗gd and I∗gq, using Vgd and Vgq as control input. To
ensure that these signals are DC in steady state, we need to regulate ω at the
angular frequency of the AC system which is achieved by the action of a PLL. There
are some challenges in designing the control scheme. Igd and Igq are not decoupled
due to the existence of ωIgd and ωIgq terms as seen in (2.13). Furthermore, the
AC system voltage vt depends on the current contribution of the VSC, ig. This is
mostly because of the nonzero Thevenin impedance of the AC system.
Figure 2.14 shows the control scheme, which can mostly overcome these chal-
lenges. There are two decoupled sub-controllers controlling d and q channels. In the
d-axis controller, the error signal, ed = I∗gd − Igd, is passed through a compensator,
27
*
gdi
gdi
*
gqi
gqi
L
L
( )iK sde
( )iK sqe
du
qu
tdv
tqv
*
gqv/
/
*
gdvdm
qm
0.5 dcv
Decoupling signals
Dq-frame current controller
Figure 2.14. Block diagram of the current-control scheme for control plant
Ki(s), to generate the signal, ud. Two signals Vtd and −LωIgq are added to ud to
generate v∗gd. Adding Vtd as a feed-forward signal mitigates the dependence of Igd
on Vtd, while adding −LωIgq decouples Igd from Igq. Similar process is used for the
q channel. Since we are assuming SPWM switching here, dividing V ∗gd and V ∗
gq by12vdc gives the modulating signals, md and mq.
As it can be seen in Fig. 2.13, the control plant is the same for both d and q
loops. Hence, we can have the same compensator, Ki(s) for both control loops.
The simplest compensator that ensures regulation with zero steady-state error is a
proportional-integral (PI) compensator, as:
Ki(s) =kps+ ki
s(2.16)
where kp and ki are proportional and integral gains, respectively. A set of propor-
28
d
q
( )t
( )t
( )t t
( )t t
tdv
tqv
tv
Figure 2.15. A space phasor and dq rotating frame
tional gains is:
kp =Lτi
ki =Rτi
(2.17)
For this set of gains we get a first order transfer function as:
Igd(s)
I∗gd(s)=
Igq(s)
I∗gq(s)=
1
τis+ 1(2.18)
where τi is the desired time constant of the closed loop step response. The choice
of compensator parameters based on (2.17) corresponds to canceling the plant pole,
−RL, by the compensator zero, − ki
kp. This results in a first-order closed loop transfer
function which is shown in (2.18).
2.5.2 Phase-locked loop
The main advantage of control in dq reference frame is that it involves DC signals.
This is guaranteed if the angular speed of dq frame, ω(t), is equal to the angular
speed of the grid voltage phasor, ωt(t) (see Fig. 2.15). One can achieve this by forcing
angle ρ(t) to track θt(t). This can be done by the action of a phase-locked loop
(PLL). There are different methods of PLL design. This section briefly describes the
model and performance of a PLL. Figure 2.15 shows a case in which the dq frame
29
abc
dq
tav
tbv
tcv
tdv
tqv( )H s
s
( )t 1
s( )t
Figure 2.16. Block diagram of a PLL.
is lagging the grid voltage phasor vt. This means ρ(t) is smaller than θt(t). Hence,
in this case ω(t) should be increased so that the dq frame reaches vt. The leading
or lagging of dq frame compared to the voltage phasor can be known by the sign of
vtq (see Fig. 2.15). If vtq is positive it can be understood that the frame is lagging
and ω(t) should be increased. On the other hand, a negative vtg indicates a leading
frame which means ω(t) should be decreased. Figure 2.16 shows the schematic of a
PLL, which can regulate ρ(t) at θt(t). As it can be seen from Fig. 2.16, the grid
voltage is transformed to dq frame using angle ρ (the transformation is described
in Appendix A). Then, vtq is driven to zero by a compensator shown as H(s) to
generate ω, which is then fed into an integrator producing ρ. In practice, the
frequency of grid voltage varies in a small region around the nominal value ωs.
Hence, ω is variable over a narrow range around ωs. To avoid the need for large
compensator output variations in situations with severe transients, the output of
compensator is limited to small positive upper and negative lower bound, and then
offset by a constant ωs to generate ω.
Characterizing H(s) needs development of a control block diagram for the PLL.
We can express vt(t) = vt(t)ejθt(t) in dq frame as:
vtd(t) + jvtq(t) = vt(t)ejθt(t)e−jρ(t) = vt(t)e
j(θt(t)−ρ(t)) (2.19)
Using Euler’s identity expressed as ej(.) = cos(.) + j sin(.) we have:
vtq(t) = vt(t) sin (θt(t)− ρ(t)) (2.20)
30
( )t( )H s( )t t
( )e t
( )tv t
( )tqv t
s
( )t 1
s
Figure 2.17. Control block diagram of the PLL.
Assuming that ρ(t) is kept close to θt(t), (2.20) can be written as:
vtq(t) ≈ vt(t) (θt(t)− ρ(t)) = vt(t)e(t) (2.21)
Hence, the PLL can be represented by a unity-feedback control loop as shown
in Fig. 2.17. θt(t) is the reference and ρ(t) is the output signal. e(t) is the error
signal and the instantaneous peak of line to neutral grid voltage vt(t) is a time-
varying gain, and the integrator is the control plant. This objective is to design the
compensator H(s) of this control loop tunes the compensator H(s) such that ρ(t)
is tightly regulated at θt(t). Since the command signal θt(t) is a ramp function of
time, H(s) should have at least one pole at s = 0 to ensure that the controller is a
type 2 controller (i.e., overall open-loop gain includes at least two integrators.). In
the simplest case H(s) can be a proportional-integrator (PI) controller. However,
often a more complicated controller is used. In this thesis the PLL described in [35]
is used in study cases.
2.5.3 Control of DC-side voltage
Any imbalance in real power within the area between DC system and VSC shown
in Fig. 2.5 results in variations in DC voltage. Pdc should be controlled via the
VSC to ensure the power balance. Power balance can be formulated as follows in
this system:
Pext − Ploss −d
dt
(
1
2CV 2
dc
)
= Pdc (2.22)
where Pdc = Vdcidc and Pext = Vdcil and Ploss represents the losses in Rdc. The
31
third term in the left hand side of equation (2.22) is equal to the rate of change of
stored energy in the dc bus capacitor. Lumping the converter losses into the Ploss
term, we can assume that Pdc = Pg and rewrite equation (2.22) as:
(
Cdc
2
)
dV 2dc
dt= Pext − Ploss − Pg (2.23)
where Pg is the VSC ac-side terminal power. Equation (2.23) shows a dynamic
system in which V 2dc is the state variable, Pg is the control input and Pext and Ploss
are the disturbance signals. Since the VSC system enables the control of Pt and
Qt we express the control input, Pg, in terms of Pt. It can be seen from Fig. 2.5,
neglecting C as before, that the dynamics of shown system can be expressed by the
below equation:
L
−→digdt
= −R−→i g +
−→Vg −
−→Vt (2.24)
Multiplying both sides of (2.24) by 32
−→i∗g , assuming
−→i g
−→i ∗
g = i2g and applying real
operator we get:
3L
2Re
{
d−→i g
dt
−→i∗g
}
= −3
2Ri2g + Re
{
3
2
−→Vg
−→i∗g
}
− Re
{
3
2
−→Vt
−→i∗g
}
(2.25)
The second and third terms in the right side of (2.25) are Pg and Pt respectively.
Hence we have:
3L
2Re
{
d−→i g
dt
−→i∗g
}
= −3
2Ri2g + Pg − Pt (2.26)
Solving 2.26 for Pg gives:
Pg = Pt +3
2Ri2g +
3L
2Re
{
d−→i g
dt
−→i∗g
}
(2.27)
The second term in the right side of (2.27) is the real power loss in the resistor
and the third term is the instantaneous real power consumed by the inductor shown
in Fig. 2.5. Hence, substituting Pg from (2.27) in (2.23) we obtain:
(
Cdc
2
)
dV 2dc
dt= Pext − P ′
loss − Pt (2.28)
32
gdi
3
2tdV−
2
dcV
extP
tP−
lossP 2
dcsC
Figure 2.18. Block diagram of the control plant describing DC voltage control.
where, P ′loss
P ′loss = Ploss +
3
2Ri2g +
3L
2Re
{
d−→i g
dt
−→i∗g
}
(2.29)
Based on (2.28), V 2dc is the output, Pt is the control input and Pext and P ′
loss
are disturbance inputs. Figure 2.18 shows the diagram of plant described by (2.28).
Hence we can form the control scheme shown in Fig 2.19. In the outer loop of
GSC control shown in Fig. 2.19, V 2dc is compared with a reference value and the
error is fed to a compensator, Kv(s) to deliver reference current i∗dg to the inner
current control loop. Pext can be measured and used as a feed-forward signal to
the output of Kv(s) to mitigate its impact on V 2dc. We note that P ′
loss is a small
term compared to Pext. Also, Ploss can not be estimated with certainty and hence
we cannot mitigate its impact by a feed-forward term. Therefore, to eliminate the
steady state error of V 2dc due to changes in Ploss, Kv(s) should have an integrator.
Kv(s) is a PI controller designed by combining pole placement technique with
symmetrical optimum criterion described in [36].
2.5.4 Control of AC-side voltage
Independent of the objective of Pt control, Qt can be controlled as an intermediate
variable to regulate the voltage magnitude of the AC system, vt, at the PCC.
Figure 2.20 shows this control scheme. As it is shown, the difference between
vt and its reference value, v∗t , is fed to a compensator, KV ac. The output of the
compensator is added to Cωvt, which is a feed-forward signal for compensating
33
dcV
*
dcV
2(.)
2(.)
( )vK s
extP
3
2tdV−
*
gdi/
Figure 2.19. Block diagram illustrating the process of DC voltage control
( )Vac sk− 1
1is +
*
gqI gqI 3
2−
tQ AC system
voltage model tv
( )2.3
2C
C
*
tv
Compensator Limiter
Closed current
control loop
Feed-forward compensation
Figure 2.20. Block diagram illustrating the process of AC voltage regulation at thecoupling point
reactive power produced by filter capacitors, to generate I∗gq. It can be shown that,
assuming a purely inductive AC system, vt is incrementally proportional to −Igq
, with the constant of proportionality being equal to the fundamental-frequency
Thevenin reactance seen from the point of coupling [16]. In practice, as shown in
Fig. 2.20, vt depends also on Pt and, therefore, on Igd due to the resistance of the
lines. However, this dependence is negligible at the transmission level voltage.
2.6 Voltage/frequency control in islanded mode
There are situations where VSCs are connected to small grids or islands, and should
control the voltage magnitude and frequency of the island. This application of
VSCs is very useful when they are connected to a blacked out system without any
reasonable voltage and frequency support. This mode is specifically discussed in
this section and will be applied for power system restoration using VSC-HVDC
systems, which will be discussed in chapter 4. There are different ways of achieving
34
voltage/frequency (v/f) control. The method represented here is one that has been
used in the case studies of this thesis.
The three modulating signals used for the switching of the two-level three-phase
VSCs can be described as:
ma(t) = M(t) cos [2πfmt]
mb(t) = M(t) cos[
2πfmt−2π3
]
mc(t) = M(t) cos[
2πfmt−4π3
]
(2.30)
where, M(t) is the magnitude and fm is the frequency of the modulating signal.
As mentioned earlier, in this thesis, v/f control mode of VSC is utilized to control
voltage and frequency in a blacked out grid. In such a case, the frequency of the
system, which is connected to the VSC can be determined by the frequency of the
modulating signal, fm. Hence fm should be set as the nominal frequency of the
system, 60Hz. One can use the magnitude of the modulating signal to control the
magnitude of the AC terminal voltage. Figure 2.21 shows the mechanism of v/f
control. The actual AC voltage magnitude is compared with the desired reference
value; and the error is fed to a PI controller to generate the magnitude of the d-axis
component of modulating signal, Md. The q-axis component, Mq can be set equal
to zero. A free running integrator with 60Hz frequency can generate the angle of
d− q axis modulating signals. It results in generation of modulating signals as:
md(t) = Md cos [2πfmt]
mq(t) = Mq sin [2πfmt](2.31)
These signals can then be converted to abc frame based on relationships described
in Appendix A, and be used for converter switching.
2.7 Summary and conclusion
The focus of this chapter was on VSC-HVDC systems. As described, there are
different topologies of VSC systems which can be put in three categories; two-level,
three-level, and multilevel. The control of VSC systems was described based on a
real and reactive power control scheme. This scheme can be used, as elaborated, to
control DC and AC voltages by the VSC. The control design uses the decoupled
35
dq
to
abc
1
s
0
-
acv*
acv PI
abcm
2 mf
dM
qM
Figure 2.21. Block diagram of voltage/frequency control of VSC in islanded mode.
current control strategy in which d and q axis current components can be used to
regulate the real and reactive powers independently.
The content of this chapter gives adequate background to understand the way
VSC-HVDC systems are used in power grid restoration, which is a key element of
this thesis. The last section of this chapter described how VSC can control the AC
voltage magnitude and frequency in an island or an area without any voltage and
frequency support (i.e. a blacked out area). It will be shown in chapters 4 and 5
that a VSC-HVDC link can perform restoration process in a blacked out system
connected to it.
36
Chapter 3 |
DFIG-based wind farms andtheir control scheme
3.1 Introduction
Chapter 2 described the structure and controls of VSC-HVDC systems. In this
chapter, the model and controls of doubly-fed induction generator (DFIG)-based
wind energy system is presented. This chapter along with chapter 2 provides the
background for, an innovative restoration method proposed in chapter 5.
Renewable energy consists a relatively significant portion of generation in modern
power grid, which is growing at a fast pace. Of all different renewable sources such
as solar, biomass, hydro, etc., wind power has the largest share in the generation
mix.
Different types of wind turbine-generator systems are in use, which can be
broadly classified as either constant-speed (Type 1) or variable-speed systems
(Type 2, 3, and 4). Figure 3.1(a) shows simplified schematic of a Type 1 wind power
system. It is composed of a wind turbine coupled with a squirrel-cage induction
generator via a gearbox. In this type of wind power system, the machine is directly
connected to grid without any power electronic interface. Since the asynchronous
machine consumes reactive power, it is equipped with shunt capacitors as it can
be seen in Fig. 3.1(a). It should be noted that, since the induction machine is
operating in generator mode, the rotor speed is higher than the synchronous speed.
The three dominant types of variable-speed wind energy systems are shown in figs
3.1(b)-(d). Figure 3.1(b) shows schematic of a Type 2 turbine-generator system
37
Doubly-fed
induction
generator
grid
AC/DC/AC
Converter System
PCC
rP
turP
Wind
turbine
WV
tP
tQ
sPGear
box
Wound rotor
induction
generator
grid
PCC
turP
Wind
turbine
WV
tP
tQ
sPGear
box
grid
PCC
turP
Wind
turbine
WV
tP
tQ
sPGear
box
gridAC/DC/AC
Converter System
PCC
tP
tQ
sP
Synchronous/
asynchronous
generator
Squirrel-cage
induction
generator
(a)
(b)
(c)
(d)
turP
Wind
turbine
WV
Gear
box
Figure 3.1. (a) Schematic of constant-speed wind power system. Schematic of variable-speed wind power system based on (b) wound rotor induction generator without powerelectronic converters, (c) doubly-fed induction generator and power electronic converter,(d) synchronous and asynchronous generator and full power electronics conversion.
38
which is consisted of a wound rotor induction generator connected directly to the
grid. The rotor is connected to an external set of resistors and power electronics via
slip rings. The resistors and power electronics can also be mounted on the rotor to
eliminate the slip rings. These variable resistors are connected to rotor circuit softly
and can rapidly control currents in order to keep power constant during gusting
wind conditions. Figure 3.1(c) shows Type 3 wind generator, which is based on
DFIG. A power electronic converter system is used which allows bidirectional power
exchange between rotor and the grid. As it can be seen from Fig. 3.1(c), the stator
of DFIG is directly connected to grid and hence the stator frequency is determined
by the grid frequency. This type of wind power system will be described in more
detail later in this chapter. The schematic of a Type 4 wind energy system is
illustrated in Fig. 3.1(d). The used machine could be wound rotor synchronous
generator with high number of poles, permanent magnet synchronous generator, or
squirrel cage induction generator. The stator is connected to grid via a converter
system which adjusts the frequency of stator circuit excitation to allow a variable
rotor speed. In this type of system, the gearbox can be omitted so that the machine
spins at the slow turbine speed and generates an electrical frequency lower than
that of the grid.
Among these topologies, Type 3 turbines based on DFIGs (shown in Fig. 3.1(c))
are used in about 50% of variable speed wind farms [37]. The objective of this
chapter is to describe the structure and widely-used control strategies of DFIG-
based wind units. The other types of aforementioned wind turbine-generators are
not discussed in this work.
Later in chapter 5, an approach for power system black-start is proposed, which
uses these well-known modes of control commonly used in current wind energy
systems.
3.2 DFIG-based wind energy system
Figure 3.1(c) shows a schematic of a wind energy system based on DFIG. It can be
seen in Fig. 3.1(c), this structure consists of a wind turbine, a gearbox connecting
turbine and generator shaft, an induction generator, and a converter system. The
stator of the machine is directly connected to the power grid (or isolated loads) and
the rotor is connected to the AC/DC/AC converter system. The converter system
39
consists of two 2-level, three-phase back-to-back VSCs connected via a common
DC-link.
3.2.1 Wind turbine model and characteristics
Operation of a wind turbine can be characterized by its mechanical power output
as a function of wind speed, which is given by the following equation:
Ptur = 0.5ρAV 3wCp(λ, β) (3.1)
where, ρ is the air mass density, A = πr2 is the turbine swept area, r is the turbine
radius, and Vw is the wind speed. Cp is a nonlinear function of λ and β referred
to as the performance coefficient or power efficiency and is smaller than 0.59 [38].
It can assume different forms. In this thesis it is considered to have the following
form [39]:
Cp = 0.5
[
rCf
λ− 0.022β − 2
]
e−0.255rCf
λ (3.2)
where, β is the turbine pitch angle [40], λ is the tip-speed ratio, and Cf is blade
design constant. λ is defined by:
λ =rωtur
Vw
(3.3)
where, ωtur is the rotational angular speed of turbine blades. Equations (3.1) and
(3.3) show that the mechanical power of wind turbine can be controlled via β and
ωtur. The pitch angle, β, is usually set based on the power output needed from wind
farm. If electrical power is below rated value and the purpose is to generate the
maximum available power, β is set to zero. It is set to 90◦ to stop power generation
in cases like extreme wind conditions and is actively controlled in case the power
generation needs to be regulated below the maximum power level. Figure 3.2 shows
the variation of Cp with respect to λ for two different values of β. As it can be seen,
the value of Cp increases by increasing λ, reaches a peak for an optimum value of
λ, and then decreases. It is usually desirable for wind turbine systems to harness
the maximum power possible from wind. For this purpose, pitch angle β should
be set to zero. Moreover, λ should be adjusted to the optimum value, λopt, which
maximizes Cp. Under this condition, based on (3.3) we have:
40
0 2 4 6 8 10 12
λ
-0.05
0
0.05
0.1
0.15
0.2
0.25
0.3
0.35
0.4
0.45
Cp
β = 30o
β = 15o
loci of maximum
power point
Figure 3.2. Typical performance-coefficient versus tip-speed-ratio characteristic curve ofa wind turbine.
Vw =rωturopt
λopt
(3.4)
where, ωturopt is the turbine rotating speed corresponding to λopt. Substituting (3.4)
in (3.1) we obtain:
Pturmax =
(
0.5ρAr3Cpmax
λ3opt
)
ω3turopt (3.5)
where Cpmax is the maximum value of Cp corresponding to λopt and β=0.
Defining kopt =(
0.5ρAr3Cpmax
λ3opt
)
, equation (3.5) can be written as:
Pturmax = kopt ω3turopt (3.6)
(3.6) indicates that under a constant λ the maximum attainable turbine power
is proportional to the cube of turbine speed [41, 42]. We can also have a similar
equation for torque as:
Tturmax = kopt ω2turopt (3.7)
These relations are applied to achieve maximum power point tracking (MPPT).
The details of MPPT are descried in the following sections of this chapter along
41
with other aspects of DFIG control.
3.2.2 Doubly-fed induction generator model
DFIG can be considered as a traditional induction generator with a nonzero rotor
voltage. As it can be seen in Fig. 3.1(c) this machine consists of rotor and stator
windings, which are connected to back-to-back VSCs. The stator windings are
connected to the grid, which imposes the stator frequency, fo. Stator currents
create a rotating magnetic field in the air gap. The rotational speed of this field,
ωo, is proportional to the grid frequency and is defined by:
ωo = 2πfo (3.8)
where, fo is equal to the grid nominal frequency of 60Hz. The induction machine
operates with the rotor rotating at a different speed from the rotational speed of
the magnetic field. This results in flow of current with a different frequency in rotor
windings. This frequency is related to the stator synchronous frequency by:
fr = sfo (3.9)
where, s, referred to as machine slip is defined by:
s =ωo − ωr
ωo
(3.10)
The governing equations of a DFIG can be written in a d-q reference frame
42
rotating at angular speed ωo as follows [43]:
vds = Rsids +dλds
dt− ωoλqs
vqs = Rsiqs +dλqs
dt− ωoλds
vdr = Rridr +dλdr
dt− (ωo − ωr)λqr
vqr = Rriqr +dλqr
dt− (ωo − ωr)λdr
λds = Lsids + Lmidr
λqs = Lsiqs + Lmiqr
λdr = Lmids + Lridr
λqr = Lmiqs + Lriqr
Pe = λqridr − λdriqr = λdsiqs − λqsids
Te =pωoPe
(3.11)
where, p = number of pole pairs, Lss = Ls+Lm, Lrr = Lr +Lm, λs: stator flux
linkage, Lm: mutual inductance, Ls/Lr: stator/rotor leakage inductance, Rs/Rr:
stator/rotor resistance, Pe: electromagnetic power, Te: electromagnetic torque,
and ims: magnetizing current. All quantities are expressed in per unit (p.u.).
Equations in (3.11) will be used to design the control scheme of such machines,
which is described in detail in the next section.
As shown in Fig. 3.1(c) the generator is connected to the wind turbine via shafts
and gearbox. Another set of equations are needed to model the mechanical interface
between the turbine and the generator. This interface can be represented by six-
mass, three-mass, two-mass and lumped one-mass models [44]. In the one-mass
or lumped model, all types of wind turbine drive train components are lumped
together and work as a single rotating mass. These components include the blades,
hub, and shaft of wind turbine, gearbox and the generator shaft and rotating mass.
In this case the dynamic behavior can be described by:
dωr
dt=
Twt − Te
Jwt
(3.12)
In (3.12), ωr is the generator rotor speed, Jwt is the inertia constant of the rotating
mass, Twt is the input mechanical torque applied to the wind turbine rotor and Te
is the electromagnetic torque of the induction generator. This one-mass model has
been used in this work.
43
*
r
r
Figure 3.3. Block diagram of turbine pitch control (Active only when ωr crosses athreshold).
3.2.3 Pitch control
Usually, a mechanism is needed to control the amount of wind energy captured by
the turbine. This is achieved via the pitch control mechanism. This mechanism is
also useful in protecting the turbine during extreme wind conditions. High wind
speeds or a reduction in the load demand in an isolated wind farm can result in the
turbine speeding up. As shown in Fig. 3.3, in the pitch angle control mechanism,
the rotational speed of the turbine is continuously measured and compared to a
pre-set threshold level. The error is fed to a PI controller which generates the pitch
angle, β. With this process in use, an increase in the rotational speed beyond the
threshold level causes β to increase, which results in less wind power input and
hence, a decrease in rotational speed.
3.3 Control strategy of DFIGs
This section discusses common control methods for DFIGs in two modes of their
operation when connected to power grid and when feeding isolated loads. As
mentioned earlier, two back-to-back VSCs are used for controlling DFIG, which
are switched based on sinusoidal PWM described in chapter 2. These include
the rotor-side converter (RSC), connected to induction machine rotor, and the
grid-side converter (GSC), connected to induction machine stator. The generator
is controlled via these converters, which is based on decoupled current control
strategy. As mentioned in chapter 2, in this commonly-used strategy, rotor and
44
stator currents of the induction machine are converted to a rotating d− q frame
using transformations described in Appendix A. Each of these decoupled current
components can be used to control variables including AC and DC-link voltages,
and real and reactive powers. These control schemes are discussed in detail in the
following sections.
3.3.1 Grid-connected mode of control
In grid-connected mode of control, it is usually desirable to harness the maximum
available power from wind. Also, the AC voltage at the terminal of the DFIG needs
to be regulated. RSC control structure is designed to achieve these objectives. GSC
is designed to control DFIGs DC-bus voltage and the reactive power [45].
3.3.1.1 RSC control
Figure 3.4 shows the control scheme of a grid-connected DFIG-based wind turbine.
In this mode of operation, RSC is responsible for AC voltage control at PCC and
MPPT. For this purpose, the decoupled current control strategy is used. As shown
in Fig. 3.4 the d-axis rotor current idr can be used for AC voltage control, and
q-axis rotor current iqr can be used for MPPT. The AC voltage magnitude at the
PCC is regulated by droop control shown in Fig.3.4. Since the stator is connected
to grid and the effect of stator resistance is not significant, stator magnetizing
current, ims, can be considered to be constant.
The d-axis of the reference frame is aligned with the stator flux vector position.
This will give us the angle θo shown in Fig. 3.4. For this purpose, the stator flux
is estimated measuring the PCC voltage vt and the stator current is, see Fig.3.4,
and the d-axis is locked with the estimated flux vector using a phase locked loop
(PLL). The PLL model was described in section 2.5.2 in chapter 2. The following
relationship is used for flux estimation in a stationary α− β reference frame, which
can later be converted to a rotating d-q frame (see Appendix A).
λαs =∫
(vαt −Rsiαs)dt , λβs =∫
(vβt −Rsiβs)dt (3.13)
An encoder measures the rotor angle of DFIG, θr. Subtracting θr from θo gives
the slip angle θslip (see Fig. 3.4). Aligning the d-axis of reference frame with the
45
()2
* dcv (
)2
dcv
()
vKs
* qgi
qgidgi
* dgi
dtv
qtv
* dri
dri
* qri
qri
r
dcv
C
dcI
frL
frR
fgR
fgL
WV
sP
sg
=
rigi
gv
*0
gsc
Q=
tv
msi
vcK
()2
•d dt
* tv
tv
oslip
t
t
r
ofgqg
Li
ofgdg
Li
2
{(
)}
mslip
rrfr
dr
ms
ss
LL
Li
iL
++
()
slip
rrfr
qr
LLi
+
rv
si
tv
si
* drv* qrv
* dgv
* qgv
ext
P
3 2dV
−
ext
I
r
* r
2
3
opt
mms
K
pLi
−
Figure 3.4. Grid-connected DFIG-based wind farm control scheme.
46
stator flux vector position, the following equations are obtained for flux, current
and voltages:
λs = λds = Lmims = Lssids + Lmidr
iqs = −Lm
Lssiqr
vds = Rsids +dλds
dt− ωoλqs
vqs = Rsiqs +dλqs
dt+ ωoλds
vdr = (Rr +Rfr)idr + (σLrr + Lfr)didrdt
− ωslip(σLrr + Lfr)iqr
vqr = (Rr +Rfr)iqr + (σLrr + Lfr)diqrdt
+ ωslip{L2m
Lssims + (σLrr + Lfr)idr}
(3.14)
where, ωslip = ωo − ωr, σ = 1 − L2m
LssLrr, Lss = Ls + Lm, Lrr = Lr + Lm, λs:
stator flux linkage, Lm: mutual inductance, Ls/Lr: stator/rotor leakage induc-
tance, Rfr/Lfr: RSC filter resistance/inductance, Rs/Rr: stator/rotor resistance,
and ims: magnetizing current. These equations are basically the same general
equations of DFIG appearing in (3.11) with a specific alignment of the d-q frame,
and the impedance of rotor filters, Lfr and Rfr included.
As shown in Fig. 3.4, the d-axis current reference i∗dr is generated from a voltage
droop control with droop gain Kvc. The q-axis current reference i∗qr is determined
by MPPT control which is described by the following equations:
i∗qr =−2T ∗
e
3pLmims, T ∗
e = Koptω2r (3.15)
where, Te: generator’s electromagnetic torque, p: number of generator’s pole pairs
and Kopt holds the same expression as described in section 3.2.1.
The above equation shows that the optimal torque, T ∗e is proportional to iqr. It
is obvious from equation (3.14) that vqr can be used to control iqr. Furthermore,
vdr can be employed to regulate idr. The expressions for vdr and vqr shown in (3.14)
are used for control loop design. The first two terms on the right side of these
expressions could be used to design PI controllers as in equations (2.16) - (2.18),
while the third terms are feed-forward terms, see Fig. 3.4.
3.3.1.2 GSC control
The GSC is also regulated based on vector control strategy where the d-axis of the
rotating frame is aligned with the voltage−→Vt at PCC. Figure 3.4 shows GSC control
47
scheme for a grid connected DFIG. The position of PCC voltage vector is estimated
using a PLL indicated as PLL2. The purpose is to maintain the voltage constant at
its rated value at the DC link between the two converters. The d-channel of GSC
current is used for this purpose while the q-channel is utilized for reactive power
control. Assuming that the stator supplies all of demanded reactive power, Q∗gsc is
usually set to zero as shown in Fig. 3.4. The control scheme for such purposes was
described in chapter 2 under DC voltage control discussion, which can be applied
here. Hence, the details of control implementation will not be repeated here.
3.3.2 Isolated mode of control
This is the other common mode of operation of wind farms. In this mode the wind
farm is connected to and feeds isolated loads in a microgrid. In this case, in absence
of any grid support, the voltage magnitude and frequency at the terminal depend
on wind farm. Unlike the grid-connected mode, in this case MPPT cannot be
followed due to the fact that the generated power by the wind farm should match
with the load demand. The GSC performs the same DC voltage and reactive power
control as in the previous mode, while the RSC is responsible for building up and
controlling the AC voltage at the PCC as described in the next section.
3.3.2.1 RSC control
The DFIG should supply a constant voltage and frequency at its terminal and since
it is not connected to power grid its flux is no longer determined by the grid voltage
and should be regulated by rotor excitation current. A common control strategy
for a DFIG-based wind farm feeding an isolated load is proposed in [43] and is
usually referred to as the direct flux control. The d-axis of rotating reference frame
is aligned with stator flux vector as in grid-connected mode. Thus the q-axis stator
flux, λqs, is equal to zero. Similar relationships hold for voltages, currents, and
fluxes as described in (3.14). Figure. 3.5 shows the control scheme of an isolated
load-feeding DFIG.
As shown in Fig. 3.5, using (3.14) and applying appropriate feed-forward
terms, two PI controllers in the inner current control loop are used to generate the
commands v∗dr and v∗qr for RSC. From (3.14) the q-axis reference current is given
48
()2
* dcv (
)2
dcv
()
vKs
* qgi
qgidgi
* dgi
dtv
qtv
* dri
dri
* qri
qri
r
dcv
C
frL
frR
fgR
fgL
WV
sP
sg
=
rigi
gv
*0
gsc
Q=
tv
qsi
* tv
tv
* msi
msi
1 s0
2
oslip
t
r
* r
t
1s
dt
s
vR
+
/ss
mL
L−
ofgqg
Li
ofgdg
Li
2
{(
)}
mslip
rrfr
dr
ms
ss
LL
Li
iL
++
()
slip
rrfr
qr
LLi
+
rv
si
* drv* qrv
* dgv
* qgv
d
q
d q
ot
00
dcI
ext
I
3 2dV
−
ext
P
� �
Figure 3.5. Isolated DFIG-based wind farm control scheme.
49
by the following relationship:
i∗qr = −Lss
Lm
iqs (3.16)
From equations (3.14) we can get:
(
Lss
Rs
)
dims
dt+ ims = idr +
1 + σs
Rs
vdt (3.17)
where, σs =Lss−Lm
Lm
Equation (3.17) shows that idr can be used to control ims. In Fig. 3.5, a PI
controller is shown, which controls ims and uses 1+σs
Rsvdt as a feed-forward term.
The outer loop of this controller maintains a desired terminal voltage magnitude.
As shown in Fig. 3.5, the stator flux angle θo is derived directly by integrating
demanded angular frequency ω0 = 2π60rad/s. Therefore, the angle needed for the
decoupled current controls in the RSC is derived from:
θslip =
∫
ω0dt− θr (3.18)
where, θr is the rotor angle measured by an encoder as shown in Fig. 3.5.
3.3.2.2 GSC control
The control structure of GSC in DFIG’s isolated mode of control uses a rotating
frame in which the d-axis is oriented along the terminal voltage vector position and
is similar to the grid-connected mode which is described in section 3.3.1.2.
One of the complications in GSC-side control in direct flux control mode is
how to determine the terminal voltage vector position. In this mode, aligning the
voltage vector using PLL is not recommended due to the presence of harmonics
when there is no grid voltage support. As proposed in [43], the reference angle θt
to align terminal voltage vector−→Vt with the d-axis, see Fig. 3.5, could be derived
from:
θt = θ0 +π
2(3.19)
where, θ0 is the angle obtained from free running integrator described in RSC
control.
50
3.4 Summary and conclusion
This chapter described the two common methods of control for a variable-speed
DFIG-based wind energy system. These systems are typically used in a grid
connected mode or an isolated-load feeding mode. Usually in grid connected mode,
the purpose is to harvest the maximum possible power and inject it into the power
grid via a method known as maximum power point tracking (MPPT). The rotor-
side converter controls are designed for this purpose as was described in details.
The terminal AC voltage is another variable being controlled by RSC using droop
control approach. The GSC is used to retain the DC-link voltage at rated level as
well as controlling the reactive power of the converter. One PLL is utilized to align
the d-axis of GSC rotating frame with the PCC voltage and another PLL is used
to align d-axis of RSC frame with stator flux.
In the isolated mode the DFIG is controlled based on direct flux control method.
In this mode the voltage at PCC is built up by DFIG through the control of
magnetizing current by RSC. Due to the lack of voltage support from the grid, it is
not practically possible to use PLLs and hence the d-axis of RSC is aligned with
an arbitrary angle generated by a free running integrator on rated frequency. The
GSC structure is the same as grid-connected mode.
Building on these common control schemes a novel method of power system
black-start is proposed in chapter 5. Such an approach facilitates the ease of
adoption in wind generation industry, which uses such common control techniques.
The detailed switched models that were described in chapters 2 and 3 are used
to perform EMT-type simulations in EMTDC/PSCAD platform. The objective of
these simulations is to study novel control strategies involving VSC-HVDC and
DFIG-based wind farms for black-start of power system. However, black-start is a
system level analysis. Hence, these detailed models cannot be used for simulations
of large systems for black-start studies. A hybrid co-simulation platform is proposed
in chapter 4, which retains fidelity of components like VSC-HVDC links and DFIG-
based wind farms, while ensuring that simulation is computationally manageable
for a large-scale system.
51
Chapter 4 |
Novel hybrid simulation plat-form in VSC-HVDC-assistedpower system restoration stud-ies
4.1 Introduction
Power system planners traditionally use software tools that are based on positive
sequence, fundamental frequency phasor models. Examples of a few commercial
power system planning software are PSLF [46], PSSE [27], and DIgSILENT [47].
However, traditional planning software tools may not be adequate for simulating
restoration of large systems. One of the reasons behind this is the wide range
of bandwidth of interest for the system restoration including phenomena with
small time constants like transformer inrush current, voltage fluctuations, long line
switching along with relatively slower phenomena including inertial and frequency
support, and different system stability challenges. This gets even more complicated
when we consider the black-start process assisted by VSC-HVDC links.
When an HVDC link, especially VSC-HVDC, interconnects two asynchronous
AC systems, it acts as a ‘firewall’ against the propagation of blackouts. This implies
that the blackout taking place in one AC-area cannot propagate into the other.
During the North-East blackout of 2003, the 330MW VSC-HVDC link across Long
Island Sound, also known as Cross-Sound Cable (CSC), was started up under an
52
emergency order from the US Department of Energy [17]. The CSC was used
to restore service to Long Island, although it was not equipped with blackstart
controls. This link was also instrumental in stabilizing system voltage as lines,
transformers, etc. were energized, generators were synchronized and cold loads
were picked up. The dynamic voltage restoration capability was very important in
riding through these transients [17]. [48] studied black-start using VSC-HVDC for
a small system with two generators and three loads. The simulation was conducted
in EMTDC/PSCAD platform.
Simulating a large system in an EMT-type platform is computationally pro-
hibitive and unnecessary. In this chapter a ‘hybrid’ co-simulation platform for
system restoration application for large power grids is proposed that will have the
ability to capture faster transients in a certain region of the grid while the rest of
the system is modeled in the phasor-domain. The content of this chapter has been
reported in [49].
4.2 Need for hybrid co-simulation
Dynamic simulation of power grid restoration is essentially a ‘system-level’ problem.
However, it is unique in the sense that unlike traditional planning simulations, the
dynamic response of interest during restoration has a wide range of time-constants.
Challenges during restoration stem from (a) frequency, angle, and voltage stability
issues that can be represented by phasor models, and (b) faster transients like
transformer inrush and long line switching currents that demands EMTP-type
representation. None of the previous studies done on VSC-HVDC assisted sys-
tem restoration [48, 50, 51] have considered a medium or large system in their
simulation-based studies. The tasks performed by a VSC-HVDC link during system
restoration include transformer energization, line energization, generator synchro-
nization, system inertia and frequency control, cold load pickup, etc. Different
restoration functionalities of the HVDC system have been presented using EMT-
DC/PSCAD [26]-type models [48, 50, 51]. Although the simulation run-time of
such models is manageable in a small-scale system, it becomes unrealistic when
considering large power grids.
ETRAN [52] is a software that has been widely used by system planners under
such circumstances. The software converts a user-defined section of the large power
53
system model in phasor domain in PSSE [27] into a detailed three-phase model in
EMTDC/PSCAD. It represents the rest of the power system by an ideal voltage
source behind an equivalent Ybus network that retains the short circuit capacity
(SCC) as viewed from the boundary nodes. Unfortunately, such a representation
has two drawbacks:
1. It does not have any dynamic representation of the rest of the power system
2. It can not allow the simulation of system restoration of the rest of the grid or
a portion thereof
Herein comes the motivation for a ‘hybrid ’ simulation for handling this problem
where the rest of the power grid in phasor-domain will be retained and co-simulated
along with the detailed three-phase model in EMTDC/PSCAD. Such a hybrid
simulation will be able to capture different time constants of interest. The hybrid
simulation architecture is described next in detail.
4.3 Hybrid simulation architecture
A hybrid simulation approach is proposed in which the HVDC link and a region
surrounding it is represented using a detailed three-phase EMT-type model. The
reason is that the influence of HVDC in initiating system restoration is limited
up to a certain boundary of the network, beyond which, the focus of research
is into optimal resource allocation subject to the system’s static and dynamic
constraints. The rest of the system is modeled by its phasor equivalent in which
the network will be represented by the algebraic model (Ybus) and the generators by
their subtransient dynamic models. In the boundary between these two regions, the
three-phase variables are converted into equivalent phasors and this information is
exchanged between the models.
The proposed hybrid simulation architecture is shown in Fig. 4.1(a). The
detailed three-phase model runs in EMTDC/PSCAD platform using time-step of
the order of micro-seconds, and the rest of the system runs with time-step of the
order of milliseconds in PSSE [27] platform - simultaneously. The interface between
these two platforms is provided by ETRAN-PLUS [28]. The interface is performed
in the following steps -
54
ETRAN PLUS
PSCAD/EMTDC
Intel Visual Fortran Compiler
VSC-HVDC, DFIG, and
surrounding buses
(3-phase EMT model)
PSSE
.bat files
Large AC system
(phasor model)
ETRCOMPSCAD
boundary
bus
DFT+ve Seq
P, Q
Update
current
injection
PSSE
boundary
bus
Update
voltage
phase,
frequency • Map IP address
• Establish socket connection
INITAD
Hybrid Co-Simulation Platform
abc/
+,-,0funda
mental
dq/abc
E+
ETRAN PSSE -> PSCAD
ANGLE
Bus 1 ID Port
100 1 2000
E+
ETRAN Plus
Process AutoLaunch
E+
ETRAN Plus
Computer/Socket Mapping
Tstart (PSS/E Com) = 1.0
(a)
(b) (c) (d)
Figure 4.1. (a) Proposed hybrid simulation architecture. The updation of data fromPSCAD/EMTDC to PSSE and vice-versa takes place at a sampling rate, which is equalto the integration time step that is larger among the two platforms. ETRAN librarycomponents: (b) ‘ETRANPlus-Com,’ (c) ‘AutoLaunch,’ (d) ‘chan-import.’
• Creating boundary buses in PSCAD model: The boundary buses are user-
defined. From .raw loadflow files in PSSE, a Ybus matrix is created followed by
LDU reduction, which represents the network equivalent of the PSSE model
and is presented in a Network Equivalent sub-page of the PSCAD model.
The steady state short and open circuit response of this equivalent is identical
to that of the PSSE loadflow solution.
• Creating boundary buses in PSSE model: From the boundary buses of the
phasor model, the PSCAD side is modeled as dynamic loads and generators
in a positive sequence, fundamental frequency current injection framework,
Fig. 4.1(a).
• Data exchange - PSSE to PSCAD: At each integration time-step of the PSSE
case, the node voltages of the network equivalent are calculated from the
55
phasor model and are converted to the equivalent abc frame quantities using
dq − abc transformation, see Appendix A. This is used to update the bus
voltages in PSCAD boundary buses as shown in Fig. 4.1(a).
• Data exchange - PSCAD to PSSE: The boundary buses in the PSSE model
needs to update the positive sequence fundamental frequency real and reactive
powers of the dynamic loads or generation at each sample of integration time
step, see Fig. 4.1(a). If vn,p, and in,p for p : a, b, c are the sampled voltages and
and currents in three phases in the PSCAD model, then a Discrete Fourier
Transform (DFT) is performed followed by calculation of the fundamental
frequency positive sequence voltage current phasors V+ and I+, respectively.
Thereafter, the required real and reactive power can be calculated as described
in equation (4.1).
Vk,p =N−1∑
n=0
vn,p{
cos(
−2πk nN
)
+ j sin(
−2πk nN
)}
, k ∈ Z, p : a, b, c
Ik,p =N−1∑
n=0
in,p{
cos(
−2πk nN
)
+ j sin(
−2πk nN
)}
, k ∈ Z, p : a, b, c
V+ = 13
(
Vr,a + αVr,b + α2Vr,c
)
, I+ = 13
(
Ir,a + αIr,b + α2Ir,c
)
α = 1∠120◦, α2 = 1∠240◦
P+ + jQ+ = V+I∗+
(4.1)
where, subscript ‘r′ corresponds to fundamental frequency components.
The models ‘talk’ to each other by establishing ‘socket’ connection through
the mapping of IP addresses. There are several modifications needed in both
PSCAD and PSSE models for the purpose of running a hybrid simulation using
ETRAN-PLUS, which is described next.
4.3.1 PSSE-side changes
Step I: A hybrid simulation case setup starts with conversion of either a small
or large portion of a system simulated in PSSE to a PSCAD model. The detailed
three-phase model, which is intended to be simulated in PSCAD should then be
added to this created PSCAD file. This conversion is performed using ETRAN
by selecting the desired buses. These selected buses are converted to PSCAD
model along with components attached to them. The portion of the network which
56
has been converted to PSCAD using ETRAN should be removed from simulation
system built in PSSE.
Step II: The removed portion of network should be replaced by a generator
model at the boundary bus. This generator model is key for the interface to PSCAD
as the values of real and reactive power acquired from PSCAD at each time step
are used to modify this generator output. The generators’ initial real and reactive
power should be equal to the values derived by loadflow in original system in PSSE
so that the loadflow remains the same even after removing of converted portion
from PSSE simulated model.
Step III: There are three dynamic models, which should be defined in .dyr file
which includes dynamic details of all other system components for PSSE simulation.
The first model called ‘INITAD’ is intended to establish port number and IP
addresses for connection between PSSE and PSCAD. In the second model called
‘ETRCOM’ the mentioned port number is entered along with the bus number to
which the generator model is connected. This model transfers voltage magnitude
and angle data from PSSE simulation to PSCAD simulation. This transferred data
is used to update the equivalent voltage source which is representing the portion
of system modeled in PSSE. The positive sequence real and reactive power from
PSCAD simulation are calculated using DFT and the resulting data is transferred
to PSSE simulation as described in equations (4.1). The transferred data is used to
update the dynamic generator model. Since PSSE is a non-interactive software and
output channels can not be viewed during simulations, variables could be transferred
and plotted in PSCAD environment using a model called ‘CHOUT’. Details on the
dynamic definition of mentioned models is described in ETRAN-PLUS Manual [28].
4.3.2 PSCAD-side changes
Step I: An ETRAN source model called ‘Electranix-Gen’ is automatically
added to the boundary buses when ETRAN is used for the discussed conversion of
PSSE model to PSCAD which is one of the components needed to establish the
interface between two software. This source model is provided by ETRAN-PLUS
in an imported PSCAD library. It is essential that it is set to act as a dynamic
source model in its component settings.
Step II: Two components named ‘ETRANPlus-Com’ and ‘AutoLaunch’ [28]
57
which could be found in a library provided by ETRAN-PLUS should be added at
the beginning of PSCAD simulation. These are shown in Fig. 4.1(b) and Fig. 4.1(c),
respectively. The number of ports should be entered in ‘ETRANPlus-Com’ setting
as they were defined in ‘ETRCOM’ model. A variable named ‘TStart’ should
also be set in this component’s setting. This variable indicates the exact time
when interface between two software begins and should be preferably set at a
moment after the PSCAD simulation reaches a steady state. Prior to this time
PSCAD and PSSE simulations run independently without any communication.
The ‘AutoLaunch’ component is used to start PSSE simulation at the same time
when PSCAD simulation in started. This is done by entering the address of batch
file which initiates PSSE case simulation in this component’s settings. Fig. 4.1(d)
shows a component called ‘chan-import’ which can be added optionally in PSCAD
simulation to import and plot PSSE simulation variables including voltages, angles
etc. provided that the dynamic model named ‘CHOUT’ has been defined in PSSE
case .dyr file as discussed in previous subsection.
Step III: The user can add new models from PSCAD library in the PSCAD file
to expand the model. For example, in our work, the VSC-HVDC and DFIG-based
wind farm was built using the components from the PSCAD library.
A few important points should be kept in mind while performing such hybrid
simulations. It should be noted that the generator, turbine, and exciter components,
which are converted to PSCAD from PSSE require a detailed dynamic model. These
dynamic models are specified in dynamic model file (i.e. the .dyr file), which includes
dynamic details of every component in a PSSE simulation case. User should refer
PSCAD to this file by adding it’s address in these components’ settings.
One complication in the process of preparing a hybrid simulation case arises
from choosing the proper bus to connect generator model in PSSE simulation
and problem of how to keep lines between boundary bus and other buses as they
are. When a portion of the system is converted from PSSE to PSCAD the lines
connected to the boundary bus are not converted to PSCAD and they will not
exist in PSSE simulation either. A practical approach is to create an additional
bus in PSSE simulation which connects to the boundary bus by a lossless line and
connect boundary bus-connected transmission lines to this new bus. The generator
model, which should be added to PSSE simulation after deleting the converted
58
portion should also be connected to this additional bus. Such an approach solves
the discussed problems without making any practical change to the study case.
It should be noted that specific versions of Fortran compiler should be used by
PSCAD in order for this hybrid simulation platform to work. Intel Fortran V.15 [53]
has been used effectively in this work.
4.4 Simulation studies: hybrid vs non-hybrid
As shown in Fig. 4.3, a 31-bus 4-area power system with 8 generators is considered
for simulation study in this work. A bipolar VSC-HVDC link (see section 2.3 in
chapter 2) connects area #3 to area #4. A phasor model of area #1, #2, and #3
was built in PSSE software. A portion of area #3 was then converted to equivalent
PSCAD model using ETRAN, see Fig. 4.3. A detailed switched model of the VSC
HVDC link was built in PSCAD connecting area #4 to area #3, which is described
next.
4.4.1 VSC-HVDC model and controls
A PWM-controlled bipolar 2-level VSC-HVDC link is considered in this work and
the DC lines are represented by Bergeron models with rated voltage of 350kV. The
rectifier-side VSC controls the reactive power and the DC voltage using standard
current control scheme in d− q frame. During black start, the inverter-side VSC
works in AC voltage and frequency control mode to energize the system during
the initial phase. AC voltage is controlled using the magnitude of the modulating
signal. In this stage the reference for power control loop is the measured amount of
real power and hence the phase of the modulating signal comes from a free-running
oscillator. Later the control mode is shifted to AC voltage and real power control
mode. AC voltage is controlled in the same fashion and the phase of modulating
signal is used for power control. Figure 4.2 shows the VSC control mechanism for
the positive pole of the inverter. The rectifier of VSC system is in DC-bus voltage
and reactive power, Q, control mode. The details of VSC-HVDC system control
were described in chapter 2 and will not be repeated here.
59
Inveter-Side Control Diagram
dq
to
abc
-
1
s0p
dm
p
qm0
p
abcm
*p
iP
p
iP1
0
S
0
S
0 : V-f control mode
1 : V-P control mode
-
acv*
acvPI
PI
Figure 4.2. VSC-HVDC controls for the positive pole of the inverter.
4.4.2 Non-hybrid model
A non-hybrid simulation platform is considered where the system outside the
detailed three-phase model is represented by a voltage source behind an impedance
that retains the short circuit capacity (SCC) of the system model viewed from the
point of intersection. This is performed using the ETRAN [52] software. Since
the non-hybrid model does not have any representation of the dynamics of the
phasor model, it will not be adequate for dynamic simulation during the restoration
process.
4.4.3 Hybrid model
As mentioned in Section 4.3, in the hybrid model the dynamic representation of the
phasor model is retained. The phasor model in PSSE is interfaced with the detailed
three-phase model in PSCAD using the ETRAN-PLUS software. Figure 4.3 shows
the test system in a hybrid simulation platform.
4.5 Simulation results
In this study a scenario is considered where blackout occurred in a portion of area
#3 shown in Fig. 4.3. The goals are: (a) to restore that portion of the system
with the help of the VSC-HVDC link, and (b) to pick up an additional 200-MW
load connected to bus 154 (marked in red in Fig. 4.3) and supply a portion of the
60
30113002
3001
3004
3003
3005
3020
3006
154
153
152
151
102101 211
201
202
203
205
206
Area3 Area2 Area1
Phasor model in PSSE
ETRAN PLUS
interface
V-f control Vdc – Q control
Vdc1
±350 kV
2 1
G3
converter station #2 converter station #1
Positive pole
Negative pole
MetallicReturn
Area 4
Load
BR1
t=2s
Line #1
G2Line #2
Load1
G1G1
3
45
Auxiliary
Euipment
BR2
t=25s
BR4
t=30s
BR5
t=6s
BR6
t=3s
BR7
t=3.8
s
BR8
t=3s
BR9
t=3s
6
7
8
9
T1
T2
T3
Part of Area 3:
system under
restoration
BR10
t=11.2s
Detailed 3-phase model in PSCAD
Additional
200MW load
Ptie3
Ptie1
Ptie2
Figure 4.3. Hybrid simulation setup for a 8-machine, 31-bus 4-area power system witha bipolar VSC-HVDC link with metallic return connecting areas #3 and #4. Individualcircuit breakers and the time of operation of those are shown. A portion of area #3 ismodeled as detailed 3-phase network in EMTDC/PSCAD. The rest of the model is builtin phasor domain in PSSE software.
load from generators G1 and G2 in the restored area. It was assumed that the
blackout could not propagate to area #4 since the DC link was acting as a ‘firewall.’
Initially all the breakers are assumed to be open. First, the dynamic behavior of
the non-hybrid and hybrid simulation are compared when the first objective (a) is
considered, which is described next.
61
4.5.1 System restoration: hybrid vs non-hybrid
The same restoration sequence is used for both simulations and identical control
parameters are used. The results are shown in Figs 4.4 and 4.5. In these figures
Pvsc is the power output of one of the VSCs in converter station #2, P22−bus is the
power flowing through the line interfacing the phasor model and the detailed model,
f denotes the frequency measured at bus 6, and Vac is the AC voltage at bus 2.
The timing of the breaker reclosure are shown in Fig. 4.3. The steps followed for
the system restoration are described next:
Step I: Soft-start [t = 0.2s to 1s] During this stage converter #1 is in
Vdc−Q control and converter #2 is in Vac−f control mode. As shown in Fig. 4.4(a)
and (b), the AC voltage at bus 2 is ramped-up gradually using AC voltage control
illustrated in Fig. 4.3(b). This method of energization of long line and transformers
prevents inrush currents under no-load condition [48].
Step II: Pick-up auxiliary load of G1 [t = 3s] Auxiliary equipment of G1
which are modeled as a 56-MW load is picked up using the power flowing from area
#4 through the HVDC link.
Step III: Synchronizing generator G1 [t = 3.8s] Generator G1 is connected
to system after synchronization.
Step IV: Load 1 pick-up [t = 6s] Load 1, which is a 100MW load connected
to bus 6 is connected. This load is fed by VSC-HVDC and G1 is still a floating
source at this stage.
It could be seen that as expected, the non-hybrid and the hybrid models produce
same dynamic response up to this point since BR10 is open.
Step V: Closing BR10 [t = 11.2s] At this step the part of the system which
is modeled in PSSE in hybrid simulation and as a source in non-hybrid simulation is
connected to the rest by closing BR10 after synchronization. Significant oscilations
can be seen in power output of VSCs and power flow to bus 6 from bus 3020
(Fig. 4.3(a)). Figure 4.5(c) shows the zoomed view of frequency during this event.
It can be observed that the dynamic response of frequency substantially differ when
the hybrid simulation is considered. Figs 4.4(e) and (f) also show the direction and
the dynamic behavior of the power flowing into the detailed model is quite different
in the hybrid simulation from the non-hybrid simulation. Similar observations can
be made from Figs 4.4(c) and (d) for the power output of the VSC HVDC.
62
0 5 10 15 20 25 30 350
0.5
1
vac[pu]
Non−Hybrid
0 5 10 15 20 25 30 350
0.5
1
vac[pu]
Hybrid
0 5 10 15 20 25 30 35−100
0100
Pvsc[M
W]
0 5 10 15 20 25 30 35−100
0100
Pvsc[M
W]
0 5 10 15 20 25 30 350
50
100
P22−bu
s[M
W]
time[s]0 5 10 15 20 25 30 35
0
200
400
P22−bu
s[M
W]
time[s]
[a] [b]
[c] [d]
[e] [f]
Figure 4.4. Dynamic response during system restoration from: (a),(c),(e) non-hybridand, (b),(d)(f) hybrid simulation platforms.
0 5 10 15 20 25 30 3559.9
60
60.1
f[H
z]
Non-Hybrid
time [s]
0 5 10 15 20 25 30 3559.9
60
60.1Hybrid
time [s]
f[H
z]
10 15 2059.95
60
60.05
f[H
z]
time [s]
[a]
[c]
[b]
Figure 4.5. (a)-(b) Comparison of dynamic behavior of frequency at bus 6 interfacingthe detailed and the equivalent/phasor model for non-hybrid and hybrid simulations , and(c) a zoomed view of the frequency comparing responses from non-hybrid (black trace),and hybrid (grey trace) simulations.
Step VI: HVDC mode switch [t = 20s] The control mode of converter
#2 VSCs, which was in AC voltage and frequency control mode is switched to AC
voltage and power control mode as described in Section 5.3.
Step VII: Power ramping [t = 21s to 24s] In this step the power output
of G1, which was primarily floating is ramped up to 40MWs and simultaneously the
power output of each of two VSCs in station #2 has been ramped down by 20MW.
Step VIII: Synchronizing generator G2 [t = 25s] G2 is connected to the
63
25 30 35 40 45 50 550
100200300
P22−bus[M
W]
25 30 35 40 45 50 55100
150
Ptie1[M
W]
25 30 35 40 45 50 55−50
050
100
Pvsc[M
W]
25 30 35 40 45 50 55120130140150
Ptie2[M
W]
46 48 50 52 54 560
50100150
PG1[M
W]
time[s]46 48 50 52 54 560
204060
PG2[M
W]
time[s]
[a] [b]
[c] [d]
[e] [f]
Figure 4.6. Hybrid simulation: dynamic response for simulating additional load pickupin 22-bus test system shown in Fig. 4.3(a).
system after synchronization as a floating generator.
Step IX: Load 2 pickup [t = 30s] The 50-MW load at bus 2 is connected
to the system. Since VSCs are in power control mode at this stage this load is fed
from the rest of system.
Results from this section emphasize the importance of using a hybrid simulation
in such studies. Although the control schemes and parameters have resulted in a
desirable black start process, if the exact model of a large system is used in the
study, the outcome is significantly different.
In the next Section we focus on the other objective, i.e. load pickup at bus 154,
which cannot be studied using the non-hybrid model.
4.5.2 Additional load pick up: hybrid simulation
In this study a 200-MW load has been picked up at bus 154 at t = 30s. Prior to
picking up the load the sequence of events and their timing from Steps I - V are
identical to what was described in the previous section. The rest of the sequence is
described as follows:
Step VI: 200MW load pickup [t = 30s] At t = 30s the 200MW load is
connected at bus 154. As it is shown in Fig. 4.6(a) the power flow from the portion
of system modeled in PSSE is reduced following oscillations from around 230MWs
to 50MWs. At the same time the power output of each HVDC pole has increased
64
to more than 50MW, see Fig. 4.6(c).
Step VII: HVDC mode switch [t = 38s] The control mode of converter
#2 VSCs, which was in AC voltage and frequency control mode is switched to AC
voltage and power control mode as described in Section 5.3.
Step VIII: [t = 39s to 42s] From t = 39s to 42s the same process of ramping
down the power output of HVDC and increasing power output of G1 is done as
described in previous section.
Step IX: Synchronizing generator G2 [t = 42.5s] G2 is connected to
network at t = 42.5s as a floating source.
Step X: Power ramping [t = 50s to 56s] In the last step from t = 50s
to 56s power output of G1 is increased by 80MW and G2 by 45MW as seen in
Fig. 4.6(e), (f) in order to supply the power needed for the 200MW load. During
this process the power output of each HVDC pole is also reduced by 20MWs using
power control. It is easily seen in Fig. 4.6(a) that through this process power
flow reverses and starts flowing into the PSSE-side segment of the system. The
power flow in two tie lines shown in Fig. 4.3 in the phasor model are highlighted
in Figs 4.6(b) and (d). This dynamic response observed in the hybrid simulation
paradigm cannot be simulated in the non-hybrid counterpart.
4.6 Summary and conclusion
Developing a detailed EMT-type model of a large-scale system for system restoration
studies is computationally prohibitive and hence, not a feasible approach. In this
chapter a hybrid co-simulation platform was proposed and described, which can be
a powerful tool in such studies where a detailed model of HVDC system is needed
besides the need for simulation of a large power system, which cannot be performed
in a three phase EMT environment like PSCAD.
In this approach a portion of the system including VSC-HVDC can be modeled
in a three phase EMT environment like PSCAD, while the rest of system is
represented by a phasor model in software like PSSE. ETRAN PLUS can be used as
a tool to establish a proper connection between the two models and simulate them
simultaneously. A case study was presented with VSC-HVDC assisted black-start
process in the presence of a reasonably large power system. Two simulations were
performed for the same case when a portion of system is represented as a source
65
behind equivalent impedance and when the exact phasor model of that portion is
retained. It was shown that the dynamics of the large system impacts the process
of black start and the performance of control scheme used for the VSCs. With
the ETRAN PLUS-based hybrid simulation tool, the impact of load pickup or
disturbances in large system during the restoration can also be studied. This
platform will be used in chapter 5 where a novel method of black-start is proposed
using DFIG-based wind farms to assist VSC-HVDC links in the restoration process.
66
Chapter 5 |
Novel power system restora-tion strategy using DFIG-basedwind farms and VSC-HVDClinks
5.1 Introduction
Chapter 4 proposed a hybrid co-simulation platform for power system restoration
studies. This platform was shown to be a useful tool in a study where only the
detailed three phase model of a portion of system is needed like a VSC-HVDC link.
The platform was applied to a case to investigate VSC-HVDC assisted black-start
in a fairly large power system. In this chapter, the described platform is used to
analyze a proposed method of restoration, which uses DFIG-based wind farms in
conjunction with VSC-HVDC links.
Although a growing portion of generation in modern power grid comes from
wind farms, so far only conventional generators have been considered as black-start
units for power system restoration [2]. Operation of wind farms as black-start
units is a possibility when integrated with advanced wind forecasting tools, which
in turn can accelerate the restoration process. In this chapter, it is shown that
a DFIG-based wind farm can be effectively used for such purpose by means of a
seamless control transition and autonomous synchronization approach without any
need for energy storage systems.
67
The following techniques and methods are proposed and discussed in this chapter
and are employed for system restoration using DFIG-based wind farms:
1. A DC-bus pre-charging control is proposed for DFIG-based wind farms,
which can retain the DC-bus voltage following a blackout. If wind energy is
available, this pre-charged DC bus is used to operate the wind farm in stator
flux control mode and build the terminal voltage, charge a transmission line,
and simultaneously pick up load at the remote end of the transmission line.
Picking up of loads of different compositions including constant impedance,
constant power and nonlinear rectifier load is demonstrated.
2. A novel autonomous synchronization enabled by a Phasor Measurement Unit
(PMU) is proposed to interconnect the isolated DFIG system to the rest
of the AC grid. This approach automatically adapts the phase of the AC
voltage vector at a remote bus connected to the DFIG by using the rotor-side
converter (RSC) controls and aligns it with the rest of the AC system voltage
before closing the circuit breaker.
3. Finally, a ‘Hot-Swapping’ approach is proposed, which does not lead to
any discontinuous resetting of the controller states of the wind farm. This
ensures a seamless transition from the flux control mode to the traditional
grid-connected mode.
Building on the hybrid co-simulation platform discussed in chapter 4, restoration
of a portion of a reasonably large system is demonstrated to show the effectiveness
of proposed black-start method. This portion of the system includes a DFIG-
based wind farm, a VSC-HVDC connection, a synchronous generator, multiple
transmission lines, transformers, different loads, and a remote grid, which are
represented by a EMT-type model in EMTDC/PSCAD [26]. The rest of the system
consisting a 20-bus 5-generator network is simulated as a phasor model in PSSE [27].
The content of this chapter has been reported in [54].
5.2 Proposed black-start process using wind farms
It is proposed that selected wind farms can be equipped with the control systems
presented here and be designated as black-start units. In addition to the considera-
tions mentioned in [25], it is envisioned that the wind farms used during restoration
68
DC Link
GSCRSC
Wind turbine
PWM
DFIG
PLL2encoder
RSC Controls GSC Controls
-
-
--
-
( )2*
dcv
( )2dcv-
( )vK s
*
qgi
qgidgi
*
dgidtv
qtv
-
-
*
dri
dri
*
qri
qri
r
dcv C
dcIfrL frR fgR fgL
WVsP
s gQ Q=
ri gi
gv
* 0gscQ =
Rest of
AC Grid
tv
Transmission line
Remote
loads
Breaker
-
msivcK
( )2•d
dt
*
tv
tv
qsi
1
0 S2
-
*
tv
tv
PI
*
msi
msi
PI-
1
0
S2
0
1
1
s0
2
Flux
estimationPLL1 1
0
o slip-
tlg
gv lv
PMU
Co
mm
un
ica
tio
n C
han
ne
l
g
l
-
- 0
1
0
r*
r-
PI
Pitch angle control:
(Enabled if rotor speed
surpasses treshold level)
S2
S2S1
S2 : Hot-Swapping
0 : direct flux control mode
1 : grid-connected control mode
S1 : Autonomous synchronization
0 : inactive
1 : active
t
1 sdt
s
vR
+
r
/ss mL L−
o fg qgL i
o fg dgL i
2
{( ) }mslip rr fr dr ms
ss
LL L i i
L + +
( )slip rr fr qrL L i +
rv
si
tv
si
*
drv
*
qrv*
dgv
*
qgv
d
q
d
q
o t
0 0
PI
PI
PI
PI
3
2dV−
extP2
3
opt
m ms
K
pL i
−
� �
Figure 5.1. DFIG control scheme for black-start: ‘Hot-Swapping’ and autonomoussynchronization are shown.
will be a subset of those wind farms designated as black-start units in the planning
stage. During the restoration process, accurate wind forecast tools should be used
by the system operators to determine which units can be chosen for this purpose.
The proposed black-start process using wind farms is discussed in detail in the
following sections.
5.2.1 Step I: DC-bus pre-charging controls
A challenge in operating an isolated DFIG-based wind farm is that it requires a
charged DC bus. In absence of a grid, this can be ensured by installing a battery in
each wind turbine, which could be used to charge the DC bus capacitor in the start
69
-20
-10
0
Protor[M
W]
rotor real power and DFIG DC-link voltage
6.98 7.0 7.1time [s]1.39
1.4
1.41
1.42
1.43
Vdc[kV]
[b]
[a]
[2]
GSC stops RSC stops
[1]
Figure 5.2. The DFIG-based wind farm is disconnected from the grid at t = 7.0s followedby the application of DC-bus pre-charging control. (a) Rotor power input equivalent topower flow from GSC to RSC. (b) DC-link voltage: zoomed views show the instant ofstopping GSC and RSC, respectively.
up stage. This will need additional investment and pose maintenance challenges.
To avoid this, a mechanism is proposed here to retain the charge in the DC bus
capacitor when the grid voltage support is lost following a blackout. Figure 5.1
shows the RSC and GSC of DFIG connected via the DC-link. Without loss of
generality, let us assume the flow of power in the DC-link is from RSC to GSC,
which can be determined from the direction of flow of the DC-link current Idc
in Fig. 5.1. When loss of grid voltage is sensed, switching of GSC is stopped.
This will cause an immediate rise in the DC-link voltage. However, switching in
RSC is continued to allow the capacitor to discharge through it, which causes a
gradual decrease in DC voltage. When the DC voltage comes back to its rated value,
switching of RSC is stopped. If power flows from GSC to RSC the described process
should be reversed. It can be observed from results in Fig. 5.2 that the proposed
strategy can successfully restore the voltage to its rated value within a short time
period and maintain a pre-charged DC bus. A fact which can adversely affect the
the charge retainment in capacitors is their internal losses. In fact the charge can be
retained in the capacitors for a specific period and they will discharge gradually by
time. However, another approach can be used which guarantees that the capacitors
are kept charged during the blackout, using the wind turbine-generator. As shown
in fig. 5.3, operating the DFIG-based wind farm in isolated mode using the control
scheme described in chapter 3, DC-link capacitors can be kept charged even if the
70
0 2 4 6time [s]
1
1.5
2
Vdc[kV]
DFIG DC-link voltage
Figure 5.3. DC link voltage magnitude when the DFIG-based wind farm operates inisolated mode with open terminal.
PCC of wind farm is open-circuited. Although operating the wind farm in this
condition results is a very distorted voltage at the terminal, it fulfills our purpose to
keep the DC-link voltage at its rated value until the black-start process is initiated.
If wind energy is available, the DFIG-based wind farm designated as black-start
unit will start operating in the direct flux control mode to charge transmission line
and pickup remote loads, which is described next.
5.2.2 Step II: Line charging and load pickup
At the beginning of the restoration process, using the pre-charged DC bus in Step I,
the wind farm can perform line and transformer charging, and load pickup. These
loads are not necessarily local but can be located far from the wind farm as shown
in Fig. 5.1. In this step the DFIG-based wind farm operates in direct stator flux
control mode which is shown in fig. 5.1 and builds up the terminal voltage vt. As
shown in Fig. 5.1, in this control mode the switch S2 is in position ′0′.
The details of this control mode for GSC and RSC were described in details in
chapter 3 and hence, are not repeated here.
After building up the PCC voltage vt, the wind farm can charge the transmission
line and pick up remote loads shown in Fig. 5.1. Assuming that the rest of the
AC grid will also undergo restoration process in parallel, the objective now is to
synchronize the wind farm to the rest of the grid, which is described next.
71
5.2.3 Step III: PMU-enabled autonomous synchronization
When the grid on the other side of the breaker shown in Fig. 5.1 is restored it is
likely that the voltage on each side of the breaker differ in phase. Therefore, a
synchronization method is necessary before this breaker is closed. Figure 5.4 shows
the proposed synchronization mechanism. In this context, the following points
should be noted:
• The phase of the voltage of the islanded system charged by the wind farm is
determined by integrating the rated frequency ω0 shown in Figs 5.1 and 5.4,
which is performed by digital control systems. Due to a finite resolution, its
frequency could be slightly different from the rest of the grid – we denote this
by ωo + ∆ω. As a result, there is a time-varying phase difference between
voltage vectors on the two sides of the breaker denoted by−→Vl and
−→Vg in Fig.
5.4.
• The goal is to align the voltage vector ~Vl with that of ~Vg using the controls of
the wind farm.
Since ~Vt and ~Vl have the same frequency ω0 +∆ω; their phase difference (θt − θl) is
constant, which depends on the transmission line impedance and the current iWF .
As shown in Fig. 5.4, before synchronization, the space vectors can be represented
with respect to a rotating voltage reference frame aligned with ~Vg. Mathematically,
~Vg = Vg
~Vl = Vl ej(θl−θg) = Vl e
jϕ(t)
~Vt = Vt ej(θt−θg) = Vt e
jγ(t)
(5.1)
We assume that PMUs are installed in the remote substation where the breaker is
located, which can measure the phase difference ϕ(t). All substations are equipped
with standby power supply for operating essential equipment during outages, which
will ensure PMUs operate under a blackout. As shown in Figs 5.1 and 5.4, it is
proposed that this phase difference ϕ(t) will be communicated to the wind farm
using dedicated fiber-optic channels, which in turn will be continuously subtracted
from the free running integrator angle θ0, eventually controlling θt. As shown in
Fig. 5.4, this process shifts ~Vt by a phase angle ϕ(t) and aligns vector ~Vl with ~Vg.
Let to be the time when synchronization begins and let Ts be the sampling time of
72
AC Grid
g
transmission
line
DFIG
-
g
-
( )t( )t
Frequency
Before autonomous
synchronization
Before autonomous
synchronization
PMU
Frequency
g-
Communication channel
tV lV gV
o = + o=
tV
lV
gV
( ) ( ) t lt t − = −
1
s0
o
o
o + o +
d
q
After autonomous
synchronization
After autonomous
synchronization
tV
lV gV
oo +
o +
d
q
t l −
2
t
Breaker
WFi
( )t
( )t
ltl
l
Figure 5.4. Proposed PMU-enabled Autonomous Synchronization.
the PMU. After attaining steady state, we have,
~Vg = Vg
~Vl = Vl ej(∆ωs⌊(t−t0)/Ts⌋Ts)
~Vt = Vt ej(∆ωs⌊(t−t0)/Ts⌋Ts+θt−θl)
(5.2)
where, ⌊x⌋ represents floor of x. Since ∆ωsTs is quite small, ~Vg and ~Vl are almost
in-phase.
5.2.4 Step IV: Hot-swapping
When the autonomous synchronization process is complete and the voltages ~Vl and~Vg on two sides of the circuit breaker in the remote substation shown in Fig. 5.1 are
in the same phase, the breaker is closed. The breaker status is communicated to
the DFIG-based wind farm, which in turn performs the proposed ‘Hot-Swapping’
operation by changing the position of the switch ‘S2’ to position ‘1’ shown in
Fig. 5.1. This modifies the RSC and GSC controls to conventional grid-connected
mode which was described in detail in chapter 3.
73
5.2.4.1 Notable points regarding ‘hot-swapping’
• PLL1 and PLL2 run from the beginning of the DFIG operation. Although
the output of the PLLs are used only after the ‘Hot-Swapping.’
• The proposed approach does not require switching of any dynamic states of
the controllers. This ensures a seamless transition.
5.3 VSC-HVDC controls for black-start
A bipolar VSC-HVDC system with metallic return is considered. The control mode
of VSC-HVDC system is identical to what described in chapter 4. It is assumed
that the rectifier is connected to a system unaffected by the blackout and operates
in reactive power and DC voltage control mode using traditional vector control [31].
V-f/V-P control Vdc – Q control
Vdc1
±350 kV
2 1
G3
converter station #2 converter station #1
Positive pole
Negative pole
Metallic Return
Load4
BR1
Line #1
G2Line #2
Load3
3
45
Load1
BR5
t=4.5s
BR7
t=6s
BR6
t=4s
6
7
T1
BR3
t=11s
Line #3
DFIG_based
wind farm
Load2
8
BR2
t=2s
BR4
t=14s
Blacked out area
Healthy
system
0.575/27.6 27.6/345
30113002
3001
3004
3003
3005
3020
3006
154
153
152
151
102101 211
201
202
203
205
206
Area2 Area1
3-area, 6-machine grid
Rest of
Area3
Part of
Area3
PSSE model
PSCAD model
Remote
grid
Healthy system
1tieP
20busP
vscP
Figure 5.5. Test system configuration consisting of a 3-area, 6-machine, 27-bus networkincluding a DFIG-based wind farm connected to a remote grid through a point-to-pointbi-polar VSC-HVDC link. A portion of the 3-area system is under blackout while theremote grid is healthy. Light grey: model in PSSE. Dark grey: model in PSCAD.
74
Initially, the inverter operates in AC voltage and frequency control mode to energize
the blacked-out system. After the AC system is synchronized with a generating
unit, the control mode is shifted to AC voltage and real power control mode. AC
voltage is controlled in the same fashion and the phase of the modulating signal is
used for power control. The details of VSC-HVDC control scheme were described
in chapter 2 and will not be repeated here.
5.4 Simulation study
5.4.1 System configuration
The test system shown in Fig. 5.5 consists of a 3-area, 6-machine, 27-bus network
including a DFIG-based wind farm connected to a remote grid, represented by an
ideal voltage source, through a point-to-point bi-polar VSC-HVDC link. Most of the
system is similar to the system used for simulation studies in chapter 4. A part of
area 3 in the 27-bus network is under blackout while the remote grid is healthy. The
portion of the blacked-out system connected to the remote healthy grid through the
HVDC transmission system is shown in dark grey, which is presented by a detailed
3-phase model in PSCAD [26]. The rest of the 3-area network, which is healthy, is
shown in light grey and is represented in a phasor framework in PSSE [27]. The
hybrid simulation is run using the ETRAN-PLUS [28] software.
5.4.2 Cold load effect
Cold load effect is a phenomenon appearing during system restoration in which
the loads consume significantly more power than their rated values when being
reconnected to grid after a period of disconnection. This phenomenon is the result
of a number of effects including inrush currents to cold lamp filaments, motor
starting currents, which can be up to 6 times the normal current, and motor
accelerating currents. The cold load model considered for the study in this thesis
follows reference [55]. At the beginning, the active power consumption is about
2.7 pu. The power consumption stays at that level for about 2 minutes and then
gradually decreases to 1.2 pu over a 20-minute time interval.
75
5.4.3 Simulation results
Assuming that blackout occurred in the area shown in Fig. 5.5, the purpose is to
perform restoration process in this area using both the DFIG-based wind farm
and the VSC-HVDC link, simultaneously. The wind farm starts operating in the
flux control mode and picks up remote loads marked as Load 1. In parallel, the
VSC-HVDC link charges lines #1 and #2, and the transformers using the softstart
process described in [50] and picks up Load 2 followed by Loads 3 and 4. When
the two terminals of the circuit breaker BR4 are live, the process of autonomous
synchronization and Hot-Swapping are performed and the wind farm is connected
to the rest of the grid. The details of the restoration process are described next.
� Wind speed fluctuations: It is assumed that the wind energy is available based
on forecast at the location of the wind farm. Figure 5.6(a) shows the wind speed
profile during the period of system restoration. A slow decline, sharp reduction and
increase, and random fluctuations in the wind speed are considered to evaluate the
performance of the proposed restoration strategy under challenging circumstances.
12
14
16
18
Vw[m
/s]
wind speed and pitch angle
0 8 16 24 32time [s]
0
5
10
15
β[deg]
[a]
[b]
Figure 5.6. (a) Wind speed profile. (b) Variation in wind turbine pitch angle.
� Load composition: Different types of loads are considered for reflecting the
load diversity. These include constant impedance, constant power, and nonlinear
loads.
� Voltage buildup, line charging & load pickup by wind farm [t = 0.0s - 12.0s]:
The wind farm starts it’s operation in flux control mode using the pre-charged
DC bus and builds up the voltage at its terminal using the outer voltage control
loop in the RSC control shown in Fig. 5.1, which in turn generates i∗ms. Figure 5.7
76
0
100
200
i ms[kA]
magnetizing current and wind farm voltage at PCC
ims
i∗ms
0 2 4 6 8 10time [s]
0
0.5
Vt[kV]
Vt
V ∗
t
[a]
[b]
Figure 5.7. Build up of (a) magnetizing current and (b) terminal voltage of DFIG-basedwind farm during line charging and simultaneous remote load pickup.
1.3
1.4
1.5
Vdc[kV]
DC link voltage and power consumption in remote loads
Vdc
V ∗
dc
0 2 4 6 8 10 12time [s]
0
200
PQ
load[M
W,M
VAr]
Pload
Qload
[a]
[b]
Figure 5.8. (a) DC-link voltage of the DFIG-based wind farm and (b) the powerconsumed by the remote loads at bus 8 picked up by the wind farm.
shows magnetizing current and terminal voltage build-up by the wind farm, while
charging the 345-kV, 50-km line (line #3) and simultaneously picking up a remote
load at bus 8 in Fig. 5.5. The load consists of three components: (a) a 100MW
and 35MVAr constant impedance load, (b) a 20MW and 10MVAr constant power
load, and (c) a 100MW nonlinear rectifier load. It can be seen from Fig. 5.7(b)
that the terminal voltage reaches its rated value in about 6.0s and the load power
consumption shown in Fig. 5.8(b) steadily increases, while the DC-link voltage
(Fig. 5.8(a)) is tightly regulated by the GSC controls.
Additional loads at bus 8 were picked up in the following sequence: (i) at
77
-500
0
500
v8a[kV]
build up of phase-a voltage in both sides of BR4
1 4 8 12-500
0
500
v7a[kV]
0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 1.1 1.2 1.3
time [s]
-500
0
500
v7a,v8a[kV]
[c]
[b]
[a]
Figure 5.9. Comparison of voltage build up in phase a at (a) bus 8 from the wind farmand (b) at bus 7 from VSC-HVDC. (c) Overlapping zoomed view.
t = 8.5s: a 20MW resistive load, (ii) at t = 9.5s: a 20MW resistive load, (iii)
at t = 11.0s: a 10MW, 10MVAr constant impedance load, and finally (iv) at
t = 12.0s: a 20MW, 5MVAr constant power load. Figure 5.8 shows the load power
consumption increases in steps while the DC bus voltage controller demonstrates
good tracking performance. The wind speed profile throughout this process is
higher than the wind farm’s rated wind speed of 13.5m/s, which results in the
variation in pitch angle β as shown in Fig. 5.6(b).
� Voltage buildup, line charging & load pickup by VSC-HVDC [t = 0.2s -
12.0s]: Simultaneously, on the VSC-HVDC side, converter #1 starts operating in
Vdc −Q control and converter #2 in Vac − f control mode to build up rated voltage
with rated frequency is the blacked out area (details of Vac − f control mode of
VSCs was described in chapter 2 for islanded operation). The AC voltage at bus 2
is ramped-up gradually during 0.2s to 1.0s, while charging line #1, which is 190km
long and the transformers between buses 6 and 7, and 6 and 3. At t = 2.0s, a
constant power 56MW, 14MVAr load is picked up at bus 7 by closing BR2 followed
by the pickup of Load 3 at t = 4.0s, which is a constant power load consuming
50MW and 37MVAr. Figure 5.9 shows the comparison of voltage build up at bus
78
8 from the wind farm and at bus 7 from VSC-HVDC. As it can be seen from fig.
5.9(b) the voltage built-up by VSC-HVDC has been performed in a soft startup
manner which has taken 1s to reach the rated voltage. Figure 5.9(b) also shows
a voltage drop at 4s at bus #7. This is a natural phenomenon for this system
since VSC is controlling the voltage at bus #2 and an increase in the loads causes
increased voltage drop across line #1 and transformers shown in fig. 5.5 (note that
we have a very weak system here).
� Synchronization and generation ramp up [t = 4.5s - 12.0s]: Synchronous
generator G2 which is a 120MVA machine, is synchronized and connected at
t = 4.5s and its power output is gradually ramped up to 100MW during t = 6.0s -
12.0s as shown in fig. 5.10. Also, the healthy portion of the 3-area 6-machine grid,
modeled in phasor framework in PSSE [27], is synchronized and connected to bus 6
of the blacked out portion modeled in PSCAD [26] by closing BR3 at t = 11.0s, see
Fig. 5.5. Figure 5.10 shows the power output of generator G2, the 20-bus system,
and the positive pole the VSC-HVDC station. This figure also shows power flow in
three tie lines inside the 20-bus system which are indicated in Fig. 5.5. It can be
seen from Fig. 5.10(b) that the power flowing through VSC-HVDC line reverses
during this phase. This can happen because the VSC is not controlling real power
flow at this stage. Moreover, when connecting the fairly large system (closing BR3)
the nature of the whole system and load flow solution determine the power flows in
the system. As it can be seen from fig. 5.10(a),(d),(e),(f) the 20-bus system injects
a significant amount of power into the rest of system and a large portion of this
power flows into the remote grid shown in fig. 5.5.
� Autonomous synchronization of DFIG [t = 10.0s - 14.0s]: Figure 5.11 shows
the dynamic response of the system when the proposed auto-synchronization is not
enabled and BR4 is closed at t = 14.0s when the phase difference ϕ(t) between
voltages v7a and v8a, shown in Fig. 5.14, is around 90deg. Over-modulation in
GSC and unacceptable transients in the DC-link voltage are observed as seen from
fig. 5.11(b),(c). This observation signifies the importance of proposed synchroniza-
tion method in this process.
Now, the proposed autonomous synchronization process is enabled at t = 10.0s,
which shows its effectiveness. Figure 5.12(a) shows that the phase difference between
voltages from both sides of BR4 changes slowly before t = 10.0s, which can be
explained by the wind farm-side frequency, which is slightly less than the grid-side
79
0
200
400
P20bus[M
W]
-100
0
100
Pvsc[M
W]
1 5 10 15 20 25 30 35time [s]
050
100
PG2[M
W]
100
150
Ptie1[M
W]
1 5 10 15 20 25 30 35time [s]
300
400
500
Ptie3[M
W]
200
250
Ptie2[M
W]
[a]
[b]
[d]
[e]
[f][c]
Figure 5.10. Power flow: (a) from 20-bus system to bus 6, (b) out of positive pole VSCstation, (c) out of generator G2, (d) from bus 153 to bus 3006, (e) from bus 152 to bus3004, and (f) from bus 205 to bus 154.
0
50
100
ϕ(t)[deg]
phase difference between two sides of breaker BR4
0.51
1.52
2.5
Vdc[kV]
13 14 15 16time [s]
-5
0
5
mdqg mdg
mqg
[b]
[c]
[a]
Figure 5.11. Dynamic performance while connecting the breaker BR4 without proposedsynchronization process: (a) Phase difference between voltages in both sides of breakerBR4. (b) DC-link voltage of DFIG. (c) GSC modulating signals.
frequency due to the finite resolution of numerical integration as highlighted in
Fig. 5.13(a). It can be seen from Fig. 5.12(a) that this process can successfully
change the phase of voltage on DFIG side of BR4 so that the two voltages have same
phase. Figure 5.13(b) shows the dynamic response of DFIG-side frequency during
the autonomous synchronization process. As it can be seen during this process
there are fluctuations in this frequency when the phase is being shifted by large
values. However, as the voltage at the two sides of breaker BR4 become in phase,
80
-50
0
50
100
ϕ(t)[deg]
phase difference and frequency of two sides of breaker BR4
4 6 8 10 12 14 16 18time [s]
59.8
60
60.2
f[H
z]
flfg
[b]
[a]
Figure 5.12. Dynamic performance while connecting the breaker BR4 following proposedsynchronization process: (a) Phase difference between voltages and (b) Frequency fromboth sides of breaker BR4.
6 8 10time [s]
59.99
59.995
60
60.005
60.01
f[H
z]
wind farmrest of grid
14 16 18time [s]
59.98
59.99
60
60.01
f[H
z]
wind farmrest of grid
[a] [b]
Figure 5.13. Frequency of two sides of breaker BR4 (a) before breaker closure and (b)after breaker closure.
the frequency fluctuations start decaying. Figure. 5.14 shows the two instantaneous
phase-a voltage waves at bus #7 and bus #8 during the synchronization process.
It is obvious that the proposed method can effectively synchronize the two voltages
in about 3 seconds.
� Breaker closure and hot-swapping [t = 14.0s]: At this stage the voltages at bus
#7 and bus #8 are perfectly synchronized. So, BR4 is closed and the DFIG-based
wind farm control is switched to grid connected mode. This control switching
is in a Hot-Swapping fashion which means there is no value presetting for PI
controllers. Figure 5.15(a) shows reference and actual value of GSC d-axis current
81
9.99 10 10.01-400
-200
0
200
400
va[kV]
v8a
v7a
10.99 11 11.01-400
-200
0
200
400
va[kV]
12.99 13 13.01time [s]
-400
-200
0
200
400
va[kV]
11.99 12 12.01time [s]
-400
-200
0
200
400
va[kV]
[a]
[d] [c]
[b]
Figure 5.14. Phase a voltages at two sides of breaker BR4 during auto-synchronization.v8a is instantaneous voltage at bus 8 and v7a is instantaneous voltage at bus 7.
-20
0
20
40
60
80
i dg[kA]
GSC d-axis current and DC link voltage
idgi∗dg
13.83 14 14.17time [s]
1.38
1.4
1.42
Vdc[kV]
Vdc
V ∗
dc
[a]
[b]
Figure 5.15. (a) DFIG GSC d-axis current and (b) DC-link voltage during closure ofBR4 at t = 14.0s and Hot-Swapping.
before and after Hot-Swapping at 14s. Figure 5.16 illustrates the reference and
actual values of RSC decoupled currents. It is obvious that in both modes these
currents are controlled at their reference values and a seamless transition occurs
during mode switch at t = 14.0s. The DC-link voltage is shown in fig. 5.15(b)
before and after Hot-Swapping. It can be seen that the DC-link voltage is tightly
controlled during both control modes with a very fast and small transient at 14s
when the Hot-Swapping takes place.
� HVDC control mode swapping [t = 30.0s]: At t = 30.0s converter #2 of the
HVDC link, which was in AC voltage and frequency control mode to perform the
black-start process, is switched to AC voltage and real power control mode to fix
82
100
150
i dr[kA]
RSC decoupled currents
idri∗dr
13.83 14 14.17time [s]
100
150
i qr[kA]
iqri∗qr
[b]
[a]
Figure 5.16. DFIG RSC currents in d and q reference frames during closure of BR4 att = 14.0s and Hot-Swapping.
the power flow through the HVDC link. The power control mode can also be used
to decrease or increase the power flow through HVDC link if desired as shown in
the studies in chapter 4. Figure 5.10(b) shows that the power flowing through
the HVDC transmission system is maintained at around 100MW flowing into the
remote grid.
5.5 A self-supporting DC-bus scheme for DFIG-
based wind farms
So far in this chapter, a restoration method using DFIG-based wind farms has
been proposed. One shortcoming in the pre-charged DC bus method discussed in
section 5.2.1 is the fact that the DC-bus capacitor will gradually discharge due
to the resistive losses. As a result of this fact, the black-start process should be
started within a specific time frame. However, the system operators might need
longer time to initiate the restoration sequence. Hence, we need a form of support
for the DC-bus voltage.
This section describes a proposed scheme for a self-supporting DC-bus in DFIG-
based wind farms, which equips the wind farm with the ability to keep its DC-bus
charged and continue the operation in absence of the grid support or any storage
system. It is shown that using the already described direct flux control and with
the availability of wind, a DFIG-based wind farm can retain the DC-bus charged
83
DC Link
GSCRSC
Wind turbine
PWM
DFIG
PLL2encoder
RSC Controls GSC Controls
-
-
-- -
3
2−
( )2*
dcv
( )2dcv-
lossP
dcP
( )vK s
*
qgi
qgidgi
*
dgidtv
qtv
-
-
*
dri
dri
*
qri
qri
r
dcv C
dcIfrL frR fgR fgL
WVsP
s gQ Q=,WF WFP QG
SC
P0
GSC
Q=
GSC
P0
GSC
Q=
ri gi
gv
WFi
* 0gscQ =
tv
-
2
ss opt
m ms
L K
L i
msivcK
( )2•d
dt
*
tv
tv
qsi
1
0
S
-
*
tv
tv
PI
*
msi
msi
PI-
1
0
S
0
11
s 02
Flux
estimation PLL1
1
0 o slip-
r*
r-
PI Pitch angle control:
(Enabled if rotor speed
surpasses treshold level)
S
S
S : control mode switch
0 : grid-connected control
mode
1 : direct flux control mode
t
1 sdt
s
vR
+
r
/ss mL L−
o fg qgL i
o fg dgL i
2
{( ) }mslip rr fr dr ms
ss
LL L i i
L + +
( )slip rr fr qrL L i +
rv
si
tv
si
*
drv
*
qrv*
dgv
*
qgv
d
q
d
q
o t
0 0
PI
PI
PI
PI
AC Grid
Load 1 Load 2
Tra
nsm
issio
n
line
BR 1 BR 2
BR 3
Grid-connected
operationLoss of grid
Self-supporting
DC-bus operation
Isolated
operation with
open terminal
Isolated
operation with
load 1 picked up
Isolated
operation with
load 2 picked up
(a)
(b)
� �
Figure 5.17. (a) Test system configuration consisting of DFIG-based wind farm and itscontrols, step up transformers, grid, transmission line and remote loads. (b) Flow chartshowing the sequence of events in case study.
even with an open-terminal. The effectiveness of the proposed method has been
verified using PSCAD/EMTDC [26] simulation.
5.5.1 Proposed approach
The proposed approach is demonstrated in Fig. 5.17. In presence of a healthy AC
system, consider a DFIG-based wind farm operating in grid-connected mode [45] as
described in detail in chapter 3. In case of a disturbance, which results in the loss
of grid support (e.g. a blackout) operators can perform the charge retaining process
described in detail in section 5.2.1. This results in the isolation of the DC-bus and
keeps the capacitor charged for a specific amount of time. However, as mentioned,
it is obvious that the capacitor will gradually discharge. Hence, we need a form of
support for the DC-bus voltage. It is proposed that at this stage the DFIG can
start operating in the direct-flux control mode [56], as described in chapter 3, to
support its DC-bus voltage even with an open terminal.
Since there is no load connected to the wind farm, it only feeds the losses of
84
-100
0
100
200
300
PQ
load[M
W,M
VAr]
Pload
Qload
-100
0
100
200
300
PQ
t[M
W,M
VAr]
Pterminal
Qterminal
0 5 10 15 20 24time[s]
1
1.5
VDC[kV]
0 5 10 15 20 24time[s]
0
0.5
1
Vt[pu]
[a] [b]
[c] [d]
Figure 5.18. (a) Real and reactive power fed to remote loads. (b) Power output of theDFIG-based wind farm. (c) DC-bus voltage. (d) DFIG-based wind farm terminal rmsvoltage.
6.98 7 7.05
1.4
1.41
1.42
VDC[kV]
8 10 12 14 16 18 20 22 24time [s]
1
1.5
VDC[kV]
[a]
[b] isolated modeoperation
Load1pickup
Load2pickup
GSC stops RSC stops
Figure 5.19. (a) Rotor power input equivalent to power flow from RSC to GSC, and(b) DC-link voltage, when the DFIG-based wind farm is disconnected from the grid att = 7.0s followed by the application of DC-bus charge retaining process. (c) DC-linkvoltage between 8s and 24s.
generators, converters and step-up transformers in this condition. This power is a
very small fraction of the wind farm capacity and hence, it is necessary to have pitch
angle control in order to prevent the rotational speed of turbines from increasing
beyond a certain limit. The method of pitch angle control was discussed in chapter
3 and will not be repeated here.
If a blackout occurs, the wind farm can keep its DC-bus charged and operate
in a no-load condition if wind is available. At the appropriate time, decided by
system operators, the wind farm, which is in an isolated control mode can perform
line charging and load pickup as part of the restoration process. The next section
85
describes the test system used for simulation to verify the proposed idea.
5.5.2 Case study and results
Figure 5.17(a) shows the test system, which consists of the DFIG-based wind farm,
step-up transformers, the power grid, and the remote loads connected to point of
common coupling (PCC) by a 50km transmission line. The sequence of events,
shown in Fig 5.17(b), can be divided into the following stages:
� Loss of grid [t = 0.0s - 7.0s]: In the first stage the wind farm starts up and
operates in the grid-connected mode as described in sec 5.5.1. The grid is modeled
as an ideal source. Figure 5.18(b), (c), and (d) show power output of the wind
farm, DC-bus voltage, and terminal voltage, respectively.
� Self-supporting DC-bus operation [t = 7.0s - 17.0s]: At t=7.0s the wind farm
is disconnected from the grid and remote loads by opening the breakers BR1 and
BR2. The switching of the GSC stops immediately. This causes the DC-bus voltage
to increase as shown in Fig. 5.19(b). However, switching of RSC continues to reduce
the voltage. When the DC voltage is back at its rated value, RSC switching is
stopped. Figure 5.19(a) shows the DC-bus voltage during this charge retaining
process. After this process, the wind farm starts operating in isolated mode to
support the DC-bus and prevent its discharging. At t=10.0s the DFIG converters
start operating in direct flux control mode with an open terminal as described
in section 5.5.1. The angles for GSC and RSC are estimated based on flux angle
rather than PLL calculation (see Fig. 5.17(a)). It can be seen from Figs. 5.18(c)
and 5.19(b) that the wind farm can control the DC-bus voltage at its rated value.
Figure 5.18(b) shows the small amount of active and reactive power generated by
the wind farm to feed the losses in DFIGs and transformers. Figure 5.20(b) shows
the instantaneous phase-a voltage at the terminal of wind farm. As it can be seen,
this voltage is highly distorted due to the no-load operation of wind farm. However,
since the main purpose in this stage is for the wind farm to regulate its DC-bus
voltage, the distortion in terminal voltage is not of concern.
� Line charging and cold load pickup [t = 17.0s - 24.0s]: At t=17.0s the
transmission line and a portion of remote loads (indicated by Load 1 in Fig. 5.17(a)),
consisting a 100MW and 35MVAr constant impedance, a 20MW and 10MVAr
constant power, and a 100MW nonlinear load, are connected to the wind farm by
86
4.92 4.94 4.96-400
-200
0
200
400
va[kV]
11.22 11.24 11.26-400
-200
0
200
400
va[kV]
19.22 19.24 19.26time[s]
-400
-200
0
200
400
va[kV]
23.22 23.24 23.26time[s]
-400
-200
0
200
400
va[kV]
[a] [b]
[c] [d]
Figure 5.20. DFIG-based wind farm’s instantaneous terminal voltage (one phase) whenoperating in: (a) grid-connected mode, (b) isolated mode with open terminal, (c) isolatedmode serving 220MW and 45MVAr remote load, and (d) isolated mode supplying anadditional 90MW and 30MVAr remote load.
closing BR1. Another 90MW and 30MVAr constant impedance load, indicated by
Load 2 in Fig 5.17(a), is picked up at 20s by closing BR3. The wind farm operating in
direct flux control mode feeds these loads as shown in figure 5.18(b). Figure 5.18(c)
shows the DC voltage being controlled during this stage with transients occurring
at load pickup instances - also see the zoomed view in Fig. 5.19(b). Figure 5.20
shows the reduction in voltage distortion after connecting the transmission line and
remote loads.
5.6 Summary and conclusion
In this chapter a new black-start method using DFIG-based wind farms and VSC-
HVDC links at the same time was proposed to have a faster restoration process.
It was shown that a wind farm equipped with both islanded and grid connected
control systems can start up in an isolated mode and pick up remote loads and
get connected to grid using an autonomous synchronization method. No energy
storage is needed to perform this process. The idea was successfully tested using
the hybrid co-simulation platform described in chapter 4, to simulate the partial
restoration process for a relatively large-scale system. There is no deviation from
what wind industry is currently developing in this proposed black-start method
since two commonly used control structures have been used. This method uses a
portion of wind farms which are designated as black-start units without any conflict
87
with their normal operation.
88
Appendix A|
Space phasor and dq referenceframe
A.1 Introduction
This Appendix includes a brief description of space phasor and transformation
formulations used to transfer abc, αβ, and dq reference frames. An extensive
discussion about space phasors and two-dimensional frames can be found in [31].
A.2 Space phasor
A three-phase AC system can be represented, analyzed, and controlled using the
concept of space phasors. Assume that fa(t), fb(t), and fc(t) are three signals of
arbitrary waveforms that satisfy the following equation:
fa(t) + fb(t) + fc(t) = 0 (A.1)
Then their corresponding space phasor F (t) also known as space vector is defined
as:F (t) = Fα(t) + jFβ(t)
= 23
[
ej0fa(t) + ej2π3 fb(t) + ej
4π3 fc(t)
] (A.2)
89
F (t) is a complex function of time and Fα(t) and Fβ(t) are the real and imaginary
components, respectively. In terms of real valued signals we can write:
[
Fα(t)
Fβ(t)
]
=2
3C
fa(t)
fb(t)
fc(t)
(A.3)
where, C is:
C =
[
1 −12
−12
0√32
−√32
]
(A.4)
In case the space phasor is known, one can find the corresponding three phase
signals by:
fa(t) = Re{
F (t)e−j0}
fb(t) = Re{
F (t)e−j 2π3
}
fc(t) = Re{
F (t)e−j 4π3
}
(A.5)
In terms of the real-valued components Fα(t) and Fβ(t) , the corresponding signals
are given by:
fa(t)
fb(t)
fc(t)
=
1 0
−12
√32
−12
−√32
[
Fα(t)
Fβ(t)
]
= CT
[
Fα(t)
Fβ(t)
]
(A.6)
where, CT is the transpose of C defined in (A.4).
A.2.1 dq-frame representation of a space phasor
Assuming a space phasor as F = Fα + jFβ, the αβ to dq-frame transformation is
defined as:
fd + jfq = (fα + jfβ) e−jε(t) (A.7)
The dq to αβ-frame transformation is achieved by multiplying both sides of (A.7)
by e−jε(t). Hence we have:
fα + jfβ = (fd + jfq) ejε(t) (A.8)
90
Based on Euler’s identity ej(.) = cos(.) + j sin(.), we can rewrite (A.7) as:
[
fd(t)
fq(t)
]
= R [ε(t)]
[
fα(t)
fβ(t)
]
(A.9)
where,
R [ε(t)] =
[
cos ε(t) sin ε(t)
− sin ε(t) cos ε(t)
]
(A.10)
Also, (A.8) can be rewritten as:
[
fα(t)
fβ(t)
]
= R−1 [ε(t)]
[
fd(t)
fq(t)
]
= R [−ε(t)]
[
fd(t)
fq(t)
]
(A.11)
where,
R−1 [ε(t)] = R [−ε(t)] =
[
cos ε(t) − sin ε(t)
sin ε(t) cos ε(t)
]
(A.12)
A direct transformation from the abc to dq-frame can be obtained by:
[
fd(t)
fq(t)
]
=2
3T [ε(t)]
fa(t)
fb(t)
fc(t)
(A.13)
where,
T [ε(t)] = R [ε(t)]C =
[
cos [ε(t)] cos[
ε(t)− 2π3
]
cos[
ε(t)− 4π3
]
sin [ε(t)] sin[
ε(t)− 2π3
]
sin[
ε(t)− 4π3
]
]
(A.14)
Similarly, direct transformation from dq to abc-frame can be obtained by:
fa(t)
fb(t)
fc(t)
= T [ε(t)]T
[
fd(t)
fq(t)
]
(A.15)
91
Appendix B|
Line-commutated HVDC
B.1 Introduction
Line-commutated converter HVDC (LCC-HVDC) technology was developed long
before VSC-HVDC systems and is a mature technology now. The majority of HVDC
links now in operation are of LCC type. The details on topology, characteristics
and control of LCC-HVDC systems can be found in [33, 57–60]. This Appendix
includes a very brief overview on LCC-HVDC systems.
B.2 Overview on LCC-HVDC
The overall structure of LCC-HVDC is similar to VSC-HVDC which is discussed in
chapter 2 and consists of rectifier and inverter-side converters, DC transmission line,
transformers, and DC and AC-side filters. LCCs are constructed using thyristor
valves instead of IGBTs which are used in VSCs. A thyristor valve can be turned
on when a positive voltage is applied across it and a gate signal is provided to it.
Unlike the IGBT which can be turned off by gate signal, thyristors can be turned
off only if a negative voltage is applied across them. One can build a so-called
Graetz bridge, which is a three-phase full-wave bridge, by arranging six thyristor
valves as in the configuration shown in fig. B.1. Graetz bridge is the basic building
block in LCCs. In this application each thyristor valve is comprised of a suitable
number of series-connected thyristors to achieve desired DC voltage rating.
The control of LCC stations is basically achieved by controlling the firing angle
of the thyristors. LCCs require a relatively strong synchronous voltage source in
92
dcv
gcv
gbv
gav
Figure B.1. Schematic of a Graetz bridge.
order to commutate; which is the transfer of current from one phase to another in
a synchronized firing sequence of the thyristor valves. Hence, they cannot properly
operate when connected to a weak grid. As a result of this, unlike VSC-HVDC,
LCC-HVDC systems lack the black-start ability. LCCs can only operate with the
ac current lagging the voltage so the conversion process demands reactive power.
This is the reason for one of the demerits of LCCs which is their high consumption
of reactive power. Under full-load condition reactive power consumption is 50−60%
of the real power. However, the consumption of reactive power changes by the
load change. Large capacitor banks are installed to meet the reactive power need
of converters. Since the reactive power demand changes with loading condition
breakers are always connected to these banks to switch them on and off as needed.
The flow of DC current in this type of converters is uni-directional and hence, power
reversal from one station to other is done by reversing the polarity of DC voltage in
both stations. Furthermore, smoothing filters are needed to reduce the harmonics.
Tap-changing transformers are usually used to connect the converters’ AC-side to
the grid. These transformers are used to bring the firing angles of the converter
stations within the nominal operating range. The footprint of LCC-HVDC converter
stations is generally large due to the need for large filters, capacitor banks, and
transformers.
93
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