Download Optimum DC-Link Solution in HVDC Wind Park Actively

Optimum DC-Link Solution in
HVDC Wind Park
Actively Interfaced to the Grid
Elforsk report 08:45
Mikael Wämundson and Fainan Hassan
January 2009
Optimum DC-Link Solution in
HVDC Wind Park
Actively Interfaced to the Grid
Elforsk report 08:45
Mikael Wämundson and Fainan Hassan
January 2009
ELFORSK
ELFORSK
Preface
Active operation of generation units can be used to benefit the local grid. With
such controllability, the investment in the grid (required to connect more
generation units) could be reduced and the amount of the installed capacity
could increase. However, such controllability requires more focus and studies
on the installed generation unit technology. In order to investigate such
capabilities, the active power control for an HVDC wind park installation was
studied in this project.
The work was carried out by Mikael Wämundson and Fainan Hassan, STRI as
a part of the Swedish wind energy research programme “Vindforsk - II" as
project V-157.
The research programme was funded by ABB, the Norwegian based EBLKompetense, E.ON Sverige AB, Falkenberg Energi AB, Göteborg Energi,
Jämtkraft AB, Karlstad Energi AB, Luleå Energi AB, Lunds Energi AB,
Skellefteå Kraft AB, Svenska Kraftnät, Swedish Energy Agency, Tekniska
Verken i Linköping AB, Umeå Energi AB, Varberg Energi, Vattenfall AB and
Öresundskraft AB.
Comments on the work and on the final report have been given by a
reference group with the following members: Johan Lilliecrona, Svenska
Kraftnät, Preben Jorgensen, Vattenfall Denmark, and Zhe Chen, Aalborg
University Denmark.
Stockholm January 2009
Anders Björck
Electricity and Power Production
ELFORSK
Acknowledgment
This study has been carried out under the Swedish wind energy research
programme “Vindforsk - II", which the authors are obliged to express their
sincere regard to.
The authors would also like to acknowledge the reference group members;
namely Johan Lilliecrona from SvK, Preben Jorgensen from Vattenfall
Denmark and, Zhe Chen from Aalborg University, for their active involvement
in the project and the precious feedback and discussions. Special thanks go to
Zhe Chen for hosting the second reference group meeting.
Sincere appreciation goes also to the contributions provided by Math Bollen
from STRI AB, and many thanks for his support, fruitful discussions and proof
reading.
Gothenburg June, 2008
Mikael Wämundson and Fainan Hassan
STRI AB
ELFORSK
Sammanfattning
Fokus i det här projektet har legat på möjligheterna att kontrollera den aktiva
effekten för en vindkraftspark ansluten till elnätet med HVDC länk. Genom att
kontrollera både aktiv och reaktiv effekt ges möjligheten att öka
tillförlitligheten och stabiliteten i elnätet samtidigt som den lokala elkvaliteten
höjs.
De här möjligheterna har studerats med hjälp av analyser och simuleringar.
De huvudsakliga begränsningarna i att kontrollera effekten från
vindkraftsparken är nätets impedans, sett från anslutningspunkten, samt
strömbegränsningen i omriktaren vid nätet. Genom att, under en kort tid,
minska den aktiva effekten som överförs kan dock mer reaktiv effekt
användas för att kompensera för transienter vid anslutningspunkten. Detta
har visats i en fallstudie där antalet frånkopplingar på grund av dippar har
halverats för utrustning med en spänningskänslighet av 0,8 p.u. Även
förbättringar i att kompensera förändringar i spänningens magnitud erhålls
genom att kontrollera den aktiva effekten. En inspelning av spänningen vid
anslutningspunkten för ett smältverk användes för att simulera
spänningsvariationer som kan ge upphov till flimmer. Genom att kontrollera
den reaktiva effekten från vindkraftsparken kunde PST-värdet (short-term
flicker severity) minskas med 13 % och genom att kontrollera både den
aktiva och reaktiva effekten minskade PST-värdet med 27 %.
För att implementera den aktiva effekt-kontrollen föreslås en DC-chopper som
en optimum lösning vilken kan arbeta med en liten tidskonstant för att
kompensera transienter på elnätet. Som komplement till denna kan någon
form av energilagring användas då ett större energibehov uppstår.
Konstruktionen av DC-choppern beskrivs i detalj tillsammans med
simuleringar, vilka påvisade bättre reglering av både PCC- och DC-spänningen
vid spänningsvariationer i elnätet. Olika typer av energilagring diskuterades
också. SMES (Super Conducting Magnetic Energy Storage) verkar mest
lovande för aktiv effektreglering, förutsatt en prisminskning och en höjning av
kapaciteten. En SMES tillhandahåller både en DC-chopper samt energilagring.
ELFORSK
Summary
The active control capability of an HVDC wind-park installation has been the
main focus in this study. Through controlling both the active and reactive
power, the wind park has the potential to contribute to power system security
measures and stabilization and in the same time improve the local power
quality.
This capability has been studied here through analytical discussions and
simulation. The impedance of the grid as seen by the wind-park installation
and the current limit of the front-end converter of the HVDC link are
highlighted as main factors to put limitations over the active operation of the
wind-park. However, reducing the active power, for short time duration,
relieves the active interface limitation and serves for better transients’
compensation. This has been shown through a case study, where a reduction
of the number of trips, due to voltage dips, with a factor of 2 has been found
for nearby equipment with voltage sensitivity of 0.8 p.u. Moreover, an
improvement of the compensation of grid voltage-amplitude variation has
been found when assuming a controllable active power. Using a three-phase
voltage data-measurement at the terminals of an arc furnace and using the
PST (short term flicker severity) as a comparison value, it has been found that
applying only reactive power control has reduced the PST value by 13 % while
controlling both the active and reactive power has reduced the PST value by 27
%.
To realize the active power control, a DC chopper has been proposed as an
optimum front-end controller, to respond fast against the transient
phenomena at the grid, which could be followed by a storage control that is
activated in case of a further need of its storage energy. A detailed design and
simulation for the current chopper has been carried out, showing that in case
of voltage amplitude variation the chopper has provided better regulation for
both the grid and the DC-link voltages. A discussion of different energy
storage controls has been also carried out. It has been shown that if less
costly and available with higher ratings, the superconducting magnetic energy
storage is a promising candidate in order to provide better interface
capability, where it could easily stand for both the chopper and the storage
performance requirements.
ELFORSK
Contents
List of Symbols and Acronyms
1
1
2
Introduction
1.1
1.2
1.3
1.4
1.5
2
HVDC front-end converter—controller description
2.1
2.2
2.3
2.4
3
3.3
3.4
4.6
5
5.4
5.5
6
6.5
45
Task definition .............................................................................. 45
Chopper control ............................................................................ 47
Storage Control ............................................................................. 49
5.3.1 SMES—Superconducting Magnetic Energy Storage .................. 49
5.3.2 Capacitors ......................................................................... 50
5.3.3 BES—Battery Energy Storage ............................................... 50
Wind park control .......................................................................... 51
Conclusions .................................................................................. 51
Evaluation of combined active-and-reactive power control
using DC-link solutions
6.1
6.2
6.3
6.4
22
Benefit of controlling the reactive power ........................................... 22
Compensation of load changes ........................................................ 23
Compensation of voltage dips in the grid........................................... 28
Voltage fluctuations causing flicker .................................................. 31
Impact of harmonics ...................................................................... 35
4.5.1 Local harmonics-generating load .......................................... 36
4.5.2 Upstream harmonics-generating load .................................... 40
Conclusions .................................................................................. 44
Active power control of HVDC wind park — DC-link solutions
5.1
5.2
5.3
12
Operational limitations—network viewpoint ....................................... 12
Operational limitations—VSC viewpoint ............................................. 15
3.2.1 Injected current limitation ................................................... 15
3.2.2 WP controller time constant ................................................. 18
3.2.3 Synchronization with the grid ............................................... 19
Need for control communication signals ............................................ 19
Conclusions .................................................................................. 20
Reactive power control using front-end converter
4.1
4.2
4.3
4.4
4.5
8
Controller Layout ............................................................................. 8
Vector control ................................................................................. 9
The controller signal flow ................................................................ 10
PCC voltage regulator .................................................................... 11
Active interface possibility
3.1
3.2
4
Background .................................................................................... 2
VSC-HVDC wind park layout .............................................................. 4
Study under focus ........................................................................... 5
Used tools and system modelling ....................................................... 6
Report outline and contributions ........................................................ 7
52
Compensation of load changes ........................................................ 52
Compensation of voltage dips in the grid........................................... 54
Compensation of voltage fluctuations causing flicker ........................... 54
Impact of harmonics ...................................................................... 58
6.4.1 Local harmonics-generating load .......................................... 58
6.4.2 Upstream harmonics-generating load .................................... 61
Conclusions .................................................................................. 65
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7
Discussion
7.1
7.2
8
66
Conclusions .................................................................................. 66
Future work .................................................................................. 68
References
Appendix—System description and per-unit calculations
70
74
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List of Symbols and Acronyms
HVAC
High voltage alternating current
HVDC
High voltage direct current
LCC
Line commutated converter
LCL
Inductance-capacitance-inductance
PCC
Point of common coupling
PLL
Phase-locked-loop
Pst
Short term flicker severity
PWM
Pulse width modulation
SVC
Static var compensator
TSO
Transmission system operator
VCC
Vector current controller
VSC
Voltage source converter
WP
Wind park
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1
Introduction
1.1
Background
More and more interest is put into renewable energy sources and wind power
has seen a considerable growth during recent years. According to the goals
set up by the Swedish Energy Administration, the installed wind power should
generate 30 TWh by year 2020. The figure has been 1 TWh in 2006, which
represents about 0.7 % of a total electric energy production of 146 TWh [8].
Depending on the individual power ratings of the generators, this means a
growth from under 900 to 3000−6000 installed wind power generators during
the next twelve years. Of these 30 TWh, 20 TWh are to be generated by land
based installations (onshore) and 10 TWh by generators at sea (offshore).
The Energy Administration is pointing out that the expansion of wind power at
sea is urgent since there are great potentials there [7].
Offshore wind turbines have longer life expectancy, due to low turbulence at
sea, than onshore [2]. Moreover, they can produce more energy due to
greater wind resources at sea compared to the nearby land, and they have
less visual impact and land usage, so that building concession is expected to
be easier to obtain.
Since a considerable part of the installations will be offshore, special interest
must be given to the means of transmission of the generated power. These
wind parks can be built at long distances from the existing grid and therefore
require a power transmission with low losses. This transmission is mainly
done using HVAC cables. The main drawback with this method is the
significant losses in the cables due to their high capacitance, limiting the
transmission distances. Studies have shown critical cable lengths of 202 km
for a 400 kV cable and 370 km for a 132 kV cable with power ratings of
500−1000 MW, where the transmission capacities are significantly reduced
[9]. Theoretically, the HVAC transmission distance can be increased if
compensation is introduced along the cable by e.g. thyristor controlled
reactors (TCR), but in practice this is difficult since the cable is at the bottom
of the sea [10].
Due to these limitations there are clear advantages to transmit the power
using HVDC cables. There will be no limit in cable length due to the cable
capacitance. Moreover, if the mono-pole configuration is used, the number of
wires will be reduced from three to two compared to HVAC transmission. Two
different alternatives of HVDC are possible: classical HVDC using line
commutated thyristors (LCC-HVDC) and VSC-HVDC using self commutated
IGBT:s or GTO:s. ABB is offering classical HVDC solutions for up to 3000 MW
transmitted power and VSC-HVDC (HVDC Light) solutions for up to 550 MW
[11]. Siemens is offering classical HVDC solutions for up to 3000 MW and
VSC-HVDC (HVDC PLUS) solutions for up to 250 MW [13]. These maximum
ratings are likely to grow in the near future.
The first installation of VSC-HVDC by ABB was in 1999 using the HVDC Light
technique. Two 70 km, 80 kV, and 50 MW HVDC underground cables were
2
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ploughed close to each other to connect the wind power plants in southern
Gotland and the power station in Visby [1][11][12]. During the evaluation of
the project, the SVC-HVAC alternative was considered. It has been found that
the HVDC light solution was more economical, in addition to a more significant
power quality improvement that it was going to introduce over the entire
Gotland AC network [12]. The first offshore version of VSC-HVDC went into
operation in the North Sea in 2005 connecting Statoil’s gas platform to the
grid [26]. Moreover, Svenska Kraftnät is now planning a reinforcement of the
Swedish transmission grid in the southern part of Sweden. This will include
VSC-HVDC installations for transmission over long distances [17].
A comparison between the different transmission systems applicable for
offshore wind parks is reported in Table 1-1, highlighting the advantages that
could be gained by implementing VSC-HVDC transmission.
Table 1-1. General comparison between different transmission systems for off-shore
wind parks.
Requirement
System simplicity [11]
Voltage control at the
connection bus [22]
Independent control of active
and reactive power [11][22]
Dependence on AC system [11]
Black start capability [9][22]
Multiterminal DC grid
[3][10][25]
Cable length for the same
transmission capacity [19]
Reactive power demand [3]
Connection to a weak or
isolated system [13] [24]
Investment costs with same
voltage level, same capacity
and rather long distance
[19][21][23]
Contribution to short circuit
power [3]
Critical fault clearing time [20]
Post-fault performance [20]
Transmission losses [20]
SVC-HVAC
LCC-HVDC
Complicated
Advantageous hardware
design
Limited
Limited
VSC-HVDC
Simple
Advantageous
Only reactive
2-quadrant
power control
Dependent
Dependent
Yes
No
Advantageous
(4-quadrant)
Independent
Advantageous
Not possible
Possible
Advantageous
Limited
Unlimited
Unlimited
Reactive
losses
Commutation Advantageous
No
No
Advantageous
More
investment
costs
Less
investment
costs
Advantageous
Yes
No
No
Shorter
Longer
Shorter
Long recovery
recovery
Advantageous Low losses
Longer
Best
High losses
The use of a VSC-HVDC connection of the wind park to the AC grid results in a
flexible installation with the possibility to mitigate a number of power quality
problems. This is introduced due to the capability to control the reactive
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power in a wide range with a very fast response. An even wider control range
can also be achieved by controlling the active power input to the grid. The use
of distributed generation and HVDC to control the voltage magnitude and
reactive power flow has been studied extensively (e.g. [14], [15], [16]).
By controlling the reactive power at the connection point it is possible to
regulate the voltage level, given that the reactive part of the source
impedance is big enough. For grid connections with lower reactance of the
source impedance, as is often the case in distribution cables, the voltage level
is not sensitive to changes in reactive power, but more depending on the
active power flow [18].
If actively controlled, HVDC wind parks will be promoted due to the better
functionality that they could provide compared to the other types of
transmission. In [6] it has been proven that an HVDC link connecting two
power systems’ areas and having both active and reactive power control
provides damping of the inter area oscillations. This is because, from the
system point of view, the four-quadrant controllability of VSC-HVDC
corresponds to an electrical machine without an inertia, which results in
improved system dynamics. Moreover, by reducing the active power, more
reactive power can be supplied without reaching the current limits of the
inverter, as will be explained in more details later.
1.2
VSC-HVDC wind park layout
Several layouts are possible for an HVDC wind park (WP). The main
requirement is to connect the medium variable-frequency AC-voltage
produced by the WP turbines to the 50 Hz HVAC utility grid. Using HVDC
technology, at least one rectifier and one inverter are required as shown by
the layout in Fig. 1.1. Generally each wind turbine is connected through a
small transformer to a common AC bus where the rectifier is connected. DC
smoothing filters are utilized at the DC-link in order to filter out the power
oscillations coming from the WP and provide smooth DC-link voltage, which is
important for a proper operation of the inverter. Moreover, an AC filter on the
utility grid side is also implemented in order to filter out the injected current
harmonics due to the switching operation of the VSC-inverter.
Off-shore
wind park
VSC
rectifier
filter and
transformer
DC transmission
cable
DC smoothing
filters
VSC
inverter
Utility
grid
Filter and
transformer
Fig. 1.1. VSC-HVDC wind park layout.
Another layout is also possible while utilizing the HVDC link. Each individual
wind power generator output could be rectified and connected to a DC grid, as
shown in Fig. 1.2. The voltage level is then increased to high voltage levels
4
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using DC/DC converters and connected to a single DC transmission cable. By
utilizing this layout, it is possible for each wind turbine to operate at its
individual optimal speed [31].
DC/DC
converter DCtransmission
cable
VSC
inverter
Utility
Filter and grid
transformer
DC
smoothing filters
Fig. 1.2 DC-grid HVDC wind park.
1.3
Study under focus
An outline of the study under focus is depicted in Fig. 1.3 by the shadowed
blocks. Connection of the wind park to the utility grid is considered using a
VSC-HVDC link. Much consideration is given to the construction of the
controller and its ability to control active and reactive power flow from the
HVDC link to the utility grid. Mitigation of several power quality problems is
possible using the HVDC link, such as voltage dips and over- and
undervoltages. In this study the ability to mitigate active power oscillations
and voltage fluctuations is in focus, however the compensation of voltage dips
and load changes is also considered.
Off-shore wind park
Communication
signal
Grid interface requirement
HVDC
LCC HVDC
VSC HVDC
Communication signal
Power transmission to the grid
HVAC
Utility grid
Reactive
power
control
Active and
Reactive
power
control
Active
power
control
controller
Fig. 1.3. Outline of different transmission and control methods.
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The active interface capability of VSC-HVDC wind park is studied by using two
different control strategies: firstly by only controlling the reactive power and
secondly by controlling both active and reactive power. Active power injection
can be controlled either at the WP, according to a command transmitted
through communication signals either from the grid operator or from the
front-end controller, or in the DC link, by using energy storage or dump load.
A combination of the two methods is also possible, as discussed later.
1.4
Used tools and system modelling
The modelling of the system, simplifications and different assumptions are
explained in the following.
Assumptions regarding the VSC-HVDC system:
•
Only the DC-link and inverter are modelled. As input from the wind park a
constant current source is considered. A change in the input active power
can be modelled as a change in the amplitude of the input current from
the current source. The IGBT switch model provided in PSCAD is used to
construct the physical model of the front-end inverter (the converter on
the utility grid side).
•
It is assumed that the wind park is able to reduce its power production
from 100 % to 20 % of the maximum value in 5 s [34][35]. A detailed
model of the wind turbines and their control is not incorporated.
Assumptions regarding the power system:
•
A simple network is defined for the development and the study of the
performance of the HVDC, as described in the appendix.
•
Since the local voltage quality at the PCC is of interest, the grid is
modelled using a Thévenin equivalent. Different voltage quality
phenomena that are transmitted from the upstream of the PCC are
modelled by the Thévenin equivalent voltage source. Downstream
transient phenomena are modelled using a local load.
Study tools:
•
PSCAD/EMTDC1 is used in the dynamic simulations, with embedded
Fortran codes for the controller.
•
Octave2 is used for mathematical analysis and data post processing.
•
Actual measurement data of the terminal voltage at an arc furnace has
been used for the study of the mitigation of the voltage amplitude
variation.
1
2
Copyright © 2008, Manitoba HVDC Research Centre.
Freely redistributable software; http://www.gnu.org/software/octave/
6
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1.5
Report outline and contributions
As it has been introduced in this chapter, the motivation and the study outline
have been presented where the main focus has been set on the control of the
power flow through the front end converter of a VSC HVDC wind park to the
grid.
A brief description of the basic inner current controller of the front-end
converter has been given in Chapter 2, which refers to [28] for a detailed
description. The design of the current controller is not the focus in this report
since it does not directly contribute to the required active operation of the
VSC HVDC towards the grid. In order to achieve such an active operation,
outer voltage controllers are implemented to control the power flow from the
HVDC wind park (WP) to the grid.
The potential of controlling both the active and reactive powers of the WP to
the grid has been analytically explored in Chapter 3 in order to introduce the
active operation capability.
Simulation results when controlling the reactive power at the connection point
of the WP has been shown in Chapter 4, where it has been assumed that the
active power is constant, for different operational cases. In order to also
control the active power, different DC solutions have been introduced in
Chapter 5.
Simulation results when controlling both active and reactive power have been
shown in Chapter 6, where the comparison with the case when controlling
only the reactive power has been carried out.
Conclusions have been given in Chapter 7.
The main contributions of this report are given in Chapter 3 and chapter 6,
where the benefits of controlling both the reactive and active powers of the
WP have been studied both analytically and through simulation in the two
chapters respectively. The theoretical analysis in Chapter 3 was initiated in
[28] but significantly worked out further as part of this project.
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2
HVDC front-end converter—
controller description
In this chapter the main controller of the HVDC front-end converter is
described. That is the VSC inverter as designated in Fig. 1.1. The controller
has been originally developed as a part of a PhD work [28] with focus on
distributed generation in the distribution grid. The design of this controller is
not the focus in this report since it does not directly contribute to the required
active operation of the VSC HVDC towards the grid. However, it has been
introduced here in order to provide a general understanding of the overall
system.
2.1
Controller Layout
A detailed layout of the VSC controller is shown in Fig. 2.1 along with the
power circuit. The main power circuit consists of a DC-link, where the rest of
the HVDC system has been decoupled by using a DC current source, a VSC
and a line filter. The line filter is modelled as an inductance-capacitanceinductance (LCL) filter, where the inductance to the grid side represents the
leakage inductance of the connection transformer.
The use of an LCL-filter has been promoted in, among others, [28] because of
its good capability of attenuating the injected current harmonics. The main
component of the controller is the vector current controller (VCC), which from
a reference current generates a control voltage that serves as an input to the
pulse width modulation (PWM) that generates the switching pattern of the
VSC.
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VSC
idc(t)
+
udc(t)
iin
ua(t)
ub(t)
C
Line
filter
uc(t)
sw(t)
+
ea(t)
ib(t)
eb(t)
ic(t)
Utility
Grid
ec(t)
Sample and hold
PWM
u*
Sample
and hold
udc(k)
OPT
i ab ( k )
u*
(abc )
DC regulator
PLL
ab/dq
q
Dq
* (k)
uab
Reference
currents
generation
e ab ( k)
ab/dq
2/3
i*dc(k)
3/2
3/2
opt (abc)
*
udc
ia(t)
dq/ ab
idq(k)
+
edq(k)
u*
dq
VCC
*
id
OVM
ed(k)
PCC
regulator
i*q
Current
limit
Demux
Fig. 2.1. Detailed layout of the controller.
2.2
Vector control
By transforming voltages and currents to a rotating dq-frame the controller is
able to control the active and reactive currents independently. The
transformation is done as follows. The three-phase components xa(t), xb(t) and
xc(t) are first represented as two rotating vectors in the αβ-frame as
⎡ 2
⎡ xα (t ) ⎤ ⎢ 3
⎢ x (t )⎥ = ⎢
⎣ β ⎦ ⎢ 0
⎢⎣
−
1
6
1
2
1 ⎤ ⎡ x (t )⎤
⎥ a
6 ⎥ ⎢ x (t ) ⎥ .
1 ⎥⎢ b ⎥
−
⎢ x (t ) ⎥
2 ⎥⎦ ⎣ c ⎦
−
(2-1)
The vectors xα(t) and xβ(t) are rotating with the angular frequency ω(t), which
represents the angular frequency of the grid voltage. Let θ(t) be the angle
defined by integrating ω(t), and the dq-frame rotates with ω(t) with respect to
the αβ-frame. Then the representation of the vectors xa(t), xb(t) and xc(t) in the
dq-frame is
⎡ xd (t )⎤ ⎡ cos(θ (t )) sin(θ (t )) ⎤ ⎡ xα (t ) ⎤
⎢ x (t ) ⎥ = ⎢
⎥.
⎥⎢
⎣ q ⎦ ⎣− sin(θ (t )) cos(θ (t ))⎦ ⎣ xβ (t )⎦
(2-2)
For vectors xd(t) and xq(t) representing currents, xd(t) will represent the active
current and xq(t) will represent the reactive current. The d-component of the
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voltage vector represents the amplitude of the three-phase line voltage. The
transformation therefore theoretically gives excellent controlling possibilities.
A correct transformation requires an exact value of the angle θ(t) to decouple
the components. However, if the PCC voltage regulation is out of concern, the
error in θ(t) does not impact the operation of the VSC, since the same angle is
used again in transforming back the dq-components of the reference voltage
signals into three-phase quantities. If voltage regulation at the connection
point is of interest, as the case here, minimization of the error in θ(t) is
required in order to produce the proper corrective command.
2.3
The controller signal flow
The signal flow through the controller to the VSC is as follows. The threephase currents (ia(t), ib(t) and ic(t)) and voltages (ea(t), eb(t) and ec(t)) are sampled
and transformed into the dq-frame. A sample rate of 5 kHz is used in this
study. Values obtained after sampling are no longer seen as functions of t but
rather of the sample event, k. To obtain the angle θ(k) needed for the
transformation, a phase locked loop (PLL) is used. The obtained voltage
vector edq and current vector idq are used together with the reference current
i*dq to generate the reference voltage vector u*dq that is needed to control the
VSC by using the VCC, which is generally a PI-controller, as shown in Fig. 2.2.
The reference currents are limited due to the physical limitations of the VSC.
Since the reference currents are given in the dq-frame various limitation
algorithms can be used, giving priority to either the active (d-component) or
reactive (q-component) current, as will be discussed in the next chapter. Also
the reference voltage is submitted to limitations to comply with the DC side
voltage (if the reference voltage is set higher than the available voltage the
VSC will be driven into overmodulation). The active reference-current
component is generated in such a way to inject maximum power available
from the DC-link, and in the same time to regulate the DC voltage. The PCC
voltage is, on the other hand, regulated by using the reactive referencecurrent component. A delay predictor is incorporated within the VCC in order
to compensate for the inherited one sample time delay of the digital controller
and in the same time maintain high bandwidth.
VCC
edq(k)
Feed-forward
vector calculation
*
i dq(k) Current
limit
+
idq(k-1) _
^i (k-1)
dq
^i (k) +
dq
_
FFdq(k)
+
+
kp
+
*
u dq
Limitation of
reference voltage
Delay
+
-
DuIdq(k)
Integrator
edq(k)
Delay
predictor
Fig. 2.2. Layout of the VCC is depicted inside the dashed frame.
10
Plant
idq
ELFORSK
The produced reference voltage is transformed back into three-phase
components, using the inverse of the matrices in (2-1) and (2-2), which are
optimized (in “OPT” as designated in Fig. 2.1) to increase the maximum
output voltage of the converter without increasing the DC-link voltage.
Switching patterns to the individual IGBTs are produced in the block “PWM”
and used as inputs to the VSC.
More details about the controller can be found in [28].
2.4
PCC voltage regulator
The q-component of the PCC voltage is set to zero by the coordinate
transformation, while the d-component (ed) represents the voltage amplitude.
Regarding the instantaneous injected reactive power (2-3), the reactive
current iq should be changed in a way to keep the voltage amplitude ed
constant. By changing iq, the instantaneous reactive power q, injected or
consumed by the WP, is also changed.
q (k ) = eq (k )id (k ) − ed (k )iq (k )
(2-3)
To change iq in such a way to regulate ed, the reference reactive current
command iq* is generated from a PI-controller that has the difference between
the measured ed and its reference value as an input.
11
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3
Active interface possibility
In this chapter the theoretical operational limits of the VSC-HVDC front-end
converter are studied. The model depicted in Fig. 3.1 is used. The WP is
connected to the grid at the PCC through the VSC-HVDC. At the PCC are also
some local loads supplied by both the grid and the WP. This simple network
represents the Thévenin equivalent of the grid as seen by the PCC, where
Rs+jXs represents the Thévenin impedance and E the Thévinin voltage source.
Utility grid
UPCC
PF, QF
PL, QL
d
E
Rs+jXs
local
loads
Bus R
Grid
loads
Pin, Qin
VSC-HVDC
WP
Fig. 3.1. Study system for the active interface possibilities.
3.1
Operational limitations—network viewpoint
To simplify the analysis assume a purely reactive feeder (Rs = 0). The power
flow through the feeder (PF and QF) represents the power mismatch between
the WP injected power (Pin and Qin) and the consumed load power (PL and QL).
The power mismatch can then be written as
PF =
U PCC E
sin δ
Xs
(3-1)
and
QF =
2
U PCC
U
E
− PCC cos δ .
Xs
Xs
(3-2)
The grid voltage angle, δ, can be eliminated by squaring and adding (3-1) and
(3-2). Using the trigonometric identity the following expression is obtained:
PF2
⎛
U2
+ ⎜ QF − PCC
⎜
Xs
⎝
2
2
⎞
⎟ = ⎛⎜ U PCC E ⎞⎟ .
⎜ X
⎟
⎟
s ⎠
⎝
⎠
(3-3)
Equation (3-3) represents the equation of a circle with a radius of UPCCE/Xs and
centred at (0,U2PCC/Xs). Different circles, referred to as power circles, can be
obtained for different parameters. The power circles are used here to define
the operational limits for the VSC-HVDC at the PCC [28]. Two main cases can
be further considered. In the first case, the change in the remote bus voltage
12
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(e.g. due to voltage dips or switching grid loads) is considered, while the PCC
voltage is kept regulated. The power circles represented by the injected WP
power with constant local loads (i.e. constant PL and QL) are shown in Fig.
3.2. In this case, the WP’s injected active power should be kept within the
following limits (assuming UPCC = 1 p.u.), in order to have a real solution for
the reactive power:
Reactive power (Qin)
PL −
E
E
< Pin < PL +
XS
XS
EUPCC
XS
(3-4)
E<1 E=1
UPCC
XS
QL
PL
Active power (Pin)
Fig. 3.2. Injected WP power for different remote bus voltage.
In the second case, the remote bus voltage is assumed constant (e.g. by
adjusting the tap-changer of the transformer) while the PCC voltage is not
regulated and is directly affected by the change of the local loads. To simplify
the analysis in this case, the local loads are assumed to be initially not
connected. Then at the connection of these loads, the PCC voltage will
instantly drop. This case is visualized in Fig. 3.3 (using E = 1 p.u. and Xs =
0.84 p.u.). In the figure, the only parameter that changes the radius and
centre of the power circles is UPCC. Only the possible operational area has been
depicted in the figure, where the active power from the WP is only injected
and the injected reactive power is not to exceed 1 p.u. in order to respect the
physical limitations of the WP.
Equation (3-3) can be rewritten as (PL and QL are both equal to zero)
2
⎛U E ⎞
U2
Qin = PCC − ⎜⎜ PCC ⎟⎟ − Pin2 ,
Xs
⎝ Xs ⎠
(3-5)
an expression that can be interpreted as follows: for a given grid voltage, E,
feeder impedance, Xs, and active power input, Pin, the reactive power input,
Qin, can be varied in order to obtain a regulated voltage at the PCC.
Assume that the WP is injecting 0.5 p.u. active power into the PCC and the
voltage at the PCC drops to 0.9 p.u. (due to switching on in the local load). It
is then found from Fig. 3.3 that approximately 0.1 p.u. more reactive power
needs to be injected to bring the voltage back to 1 p.u. (this is the vertical
13
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distance between the circles for UPCC = 0.9 p.u. and UPCC = 1 p.u. at Pin = 0.5
p.u.).
0.6
0.5
Reactive power import/export (p.u.)
0.4
0.3
.
.5
=0
0.2
p.u
U PCC
.
.7
=0
0.1
p.u
U PCC
U
=1p.u.
PCC
0
=0.9
U PCC
−0.1
p.u.
.
.
.8 p.u
U PCC=0
−0.2
.6
=0
p.u
U PCC
−0.3
−0.4
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
Active power export (p.u.)
Fig. 3.3. Operational region of the VSC regarding various voltage values at the PCC.
The operational limit, from the utility grid viewpoint, of a possible voltage
regulator at the PCC is related to the local injected active power. With the
assumption of constant active power generation at the PCC, this limit is
represented by the intersection point between any power circle and the 1 p.u.
power circle (regarding Fig. 3.3). The different intersection points related to
different voltages and active power values have been illustrated in Fig. 3.4,
where the active power at the intersection between the circle related to 1 p.u.
and the circles between 0 and 0.9 p.u. is plotted as a function of the voltage
drop (1–UPCC). The value of Xs that is used is 0.84 p.u. The size of the fullregulation area (dashed area) is decided by Xs as shown in the figure. For
operation in the full regulation area, there is a theoretical possibility to regain
the 1 p.u. voltage at the PCC. For a voltage drop of 0.5 p.u. and a local active
power generation of 0.7 p.u., the operation of a possible voltage regulator will
retain a voltage drop value due to the line limitation. If a full regulation
operation is needed in this condition, one possible way is to reduce the
generated active power (to 0.55 p.u. in this example).
It is worth to note here that Fig. 3.4 represents also the active injected power
limit for the case when E drops, where the curve in the figure represents the
upper limit of (3-4) when PL is equal to zero.
14
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1.1
1
0.9
Active power [p.u.]
0.8
Increased Xs
0.7
←
→ Decreased Xs
0.6
0.5
0.4
Full regulation area
0.3
0.2
0.1
0
0.1
0.2
0.3
0.4
0.5
Voltage drop [p.u.]
0.6
0.7
0.8
0.9
Fig. 3.4. Full regulation area regarding the injected active power and the voltage drop
at the PCC.
3.2
Operational limitations—VSC viewpoint
The operational limitations mentioned above are due to the network
parameters and they give the theoretical boundaries of local voltage
regulation at the PCC for an ideal generation plant. There are also operational
limitations due to the physical configuration of the WP itself and its control
arrangements.
3.2.1 Injected current limitation
Regarding the front-end converter, the semiconductors in the VSC do not
have an overcurrent capability. That means they can only handle a limited
current and thus the controller must include a current limiting algorithm in
order to avoid tripping of the unit due to the overcurrent protection. This
limitation will highly impact the compensation of the PCC voltage by using the
injected reactive power of the WP. Since the maximum available active power
from the WP is usually injected into the grid, a smaller amount of reactive
power is available without violating the current limit. This eventually means
that certain voltage quality phenomena at the PCC are not compensated for
because of the lack of the reactive power.
The current limitation is implemented here in the dq-frame, where the active
and reactive currents can be treated independently, by limiting the reference
currents. Two limitation algorithms, referred to hereafter as L1 and L2, are
considered and depicted in Fig. 3.5. With L1, the reactive current reference is
limited in such a way to reduce the injected current amplitude and maintain
the current-vector angle. Using L2, both of the dq-components of the
15
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Reactive current
reference current are reduced in such a way to inject as much reactive
current as possible into the grid. The limitation over the maximum allowed
reduction in the active current (ξ) will affect, in this case, the amount of the
injected reactive current. Referring to Fig. 3.5, if the current vector originally
lies at “a” and in case of a grid disturbance moves to “b”, using L1 it will be
limited to “c” while using L2 it will be limited to “e” (instead of “d”). Generally,
any limited current vector that lies between “a” and “e” could be possible.
Maximum current
amplitude
L2
d
b
e
L1
c
x
a
Active current
Fig. 3.5. Reference current limitation.
The performance of the above-mentioned two current reference limitation
methods is evaluated with regards to the transient operation in case of
voltage dips at the grid. Implementing the PCC controller that has been
described in chapter 2, which produces a reactive current reference that is
proportional to the drop of the voltage at the grid in a way to regulate it, and
applying voltage dips with different amplitudes, the regulation capability curve
is shown in Fig. 3.6. The figure has been developed analytically using Xs = 0.84
p.u. and Pin = 0.8 p.u. In the figure, the solid line is related to the case when
using the current limitation method referred to as L1, while the dashed line is
related to the case when using the current limitation referred to as L2. For a
voltage dip of 0.4 p.u. at the grid (without compensation), the voltage at the
PCC will be compensated to about 0.7 p.u. using L1 and about 0.9 p.u. using
L2.
Considering a sensitive load that is connected at the same connection point or
in a close proximity to the WP, it might be beneficial to apply L2 to ride
through the dip period. That would also depend on the dip duration and
statistics (how frequent it is) as compared to the extra cost related to the
reduction of the active injected power. Since the number of dips varies
strongly between different locations in the power system, it is not possible to
give general information on the number of dips that can be expected without
having details on the network supplying that location and the number of faults
in that network. However, a simple radial approximation of the network
16
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results in the following expression for the number of voltage dips, due to
faults, with residual voltage V (in per-unit) less than the nominal voltage (1
p.u.) [37]
N dips (V ) = k x ×
V
1−V
(3-6)
where kx is a location dependent factor. Comparison in [37][38] with both
measurements and simulations has shown that this expression is an
acceptable first approximation, where no other information is available, even
for strongly-meshed networks.
Fig. 3.6. PCC-voltage regulation capability with two current limitation methods; L1
(black solid) and L2 (blue dashed).
Equation (3-6) can also be used to evaluate the impact of mitigation
measures in the network on the number of equipment trips due to voltage
dips.
Consider as an example that equipment trips when the voltage drops below
70% of the nominal voltage. Using (3-6), the number of equipment trips per
year will be equal to, using V = 0.7, 2.33kx.
Using the current limitation algorithm L1 (solid line in Fig. 3.6) will make that
the voltage at the equipment terminals drops below 70% only when the noncontrolled voltage (E) drops below 40%. The number of equipment trips can
again be calculated from (3-6), using V = 0.4, resulting in 0.67kx. The number
of equipment trips is thus reduced by a factor 3.5.
Using the current limitation algorithm L2 (dashed line in Fig. 3.6) will make
that the voltage at the equipment terminals drops below 70% only when the
non-controlled voltage (E) drops below 25%. Using V = 0.25 in (3-6) gives
0.33kx, an improvement by an additional factor 2.
17
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The improvement depends on the immunity of the equipment. The more
sensitive the equipment is (i.e. tripping at a higher voltage) the more the
improvement is. This is shown in Fig. 3.7 for typical equipment trips when the
voltage drops below 40% to 85% of nominal.
Fig. 3.7. Number of trips (divided by kx) for different equipment immunity using PCCvoltage regulation and current limitation L1 (black solid) and L2 (blue dashed).
3.2.2 WP controller time constant
The active power produced by the WP cannot be reduced instantaneously. For
some steady state operational requirements, e.g. a system security measure,
a slow change might not be critical. However, for transient operation, the
response time should be comparatively fast. A reduction of the input active
power is beneficial for achieving a better transient performance, as implicitly
mentioned above. It is how an operational point is moved into the fullregulation area in Fig. 3.4 (regarding a certain voltage drop), and it is how
the current limit L2 is implemented. Moreover, the regulation of the active
power could be important in compensating possible power oscillations at the
grid, as is discussed later.
It is assumed here that the WP is able to reduce the active power from 100 %
to 20 % of the maximum value in 5 s. To achieve a faster response, a current
chopper is implemented at the DC-link as explained in Chapter 5.
18
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3.2.3 Synchronization with the grid
A phase locked loop (PLL) is implemented in order to estimate the grid
voltage angle θ. For a correct operation of the PCC-voltage regulator, a
minimum angle error is required [32]. However, if the PCC-voltage regulation
is out of concern, the error in θ does not impact the operation of the VSC,
since the same angle is used for the transformation from and to the threephase domain. If voltage regulation at the connection point is of interest, as
the case here, minimization of the error in θ is required in order to produce
the proper corrective command. This is investigated more in Chapter 4.
3.3
Need for control communication signals
The operational security of the transmission grid is guaranteed by the socalled “N–1 criterion”. This criterion states that the operation of the
transmission system shall be such that the loss of any single component does
not result in loss-of-load. The large power stations play an important role in
maintaining the stability of the transmission system. The dispatch of these
large power stations is therefore an important tool for the transmission
system operator (TSO) in fulfilling the N–1 criterion. Dispatcheable generation
refers to the units that are under control of the TSO, on contrary to the nondispatcheable ones.
As an example, which is visualized in Fig. 3.8, after the loss of a large
generation unit at t1, the N–1 criterion may no longer be fulfilled (due to the
margin violation). In that case the system operator intervenes within a
predefined time to ensure that the criterion is fulfilled again. The system
operator may increase the generation capacity at t2 by starting new
generation, reducing the load through voluntary or enforced load shedding, or
both. In the example, both measures were taken at t2. It should be noted here
that load shedding is very uncommon and that in all cases voluntary load
shedding (typically through deals made beforehand with large industrial
customers) will take place first. Rescheduling of generation units or switching
actions in the transmission system (e.g. capacitor banks) are the typical
measures taken.
For a large WP, it is required by the system operator that their active power
production should be adjustable by remote signals in order to contribute in
system security and protection measures [34][35]. These measures could
require either an increase or decrease in the WP production. The WP could be
accessible to the TSO (i.e. dispatcheable) through communication signals that
are used to set the active power reference for the plant, as shown in Fig. 3.9.
The communication signal line in the figure is double arrowed, since the
current information of the WP production should also be sent to the TSO.
19
Generation
Margin
Generation loss
Margin
Load and generation capacity
ELFORSK
Load
Load shedding
Predefined
time
t2
t1
Time
Fig. 3.8. Loss-of-generation measure by the TSO, the input power of the WP might
increase at t2.
Local
loads
Control
signals
VSC-HVDC
WP
WP
controller
Utility grid
(TSO)
Transients
Local
measurements
Communication
signals
Fig. 3.9. Controlled WP; dispatcheable through communication signals.
3.4
Conclusions
In this chapter the limitations of the VSC-HVDC connected WP to control the
voltage at the PCC has been described. These limitations are both due to the
network parameters and due to the physical limitations of the WP, VSC and
controller.
In the network, the main limitation to control the voltage is the impedance
seen from the WP. As the reactance is changed, so is the ability to regulate
the voltage using reactive power.
In the VSC, the main limitations are due to dimensioning of current handling
capabilities and controller bandwidth. Regarding current limiting, two different
algorithms are proposed, L1 and L2, where L2 shows a larger operational
range of the voltage. This is achieved by limiting the active power injected
from the WP. Using reduction for a longer time, consideration must be taken
20
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for extra investment in equipment and loss of profit (since the energy input is
decreased).
An extra limitation to the control capabilities is due to the regulations put on
the WP from the TSO.
21
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4
Reactive power control using frontend converter
The VSC-HVDC has the ability to both inject and consume reactive power and
can therefore be used to compensate for variations in the voltage level at its
connection point to the grid. In the previous chapter the theoretical limitations
of the active operation of the WP has been discussed. The range of voltage
compensation at the PCC is mainly decided by the current capability of the
VSC in the front-end of the HVDC WP. In general, the control system should
give priority to the active power delivery from the wind park, and the range of
reactive power available will therefore be affected by the wind situation. The
ability to control the voltage level is not limited only by the WP but also by the
network characteristics. This has been discussed in the previous chapter, and
is more explored in this chapter through simulation of different operational
cases.
4.1
Benefit of controlling the reactive power
Equation (3-5) can be simplified to see how the voltage at the PCC is affected
by the reactive power from the WP. First, assume that the active power input
is zero. Then
2
U PCC
− U PCC E
Qin =
.
Xs
(4-1)
Now, assume that the voltage at the PCC is to be kept at 1 p.u. This results in
a reactive power input that is dependent on the grid voltage and the feeder
impedance as
Qin =
1− E
.
Xs
(4-2)
It is seen from the equation that a longer or more reactive feeder allows for a
lower grid voltage to be compensated, given a certain limit for the available
reactive power.
In the discussion above the voltage at the PCC is kept at 1 p.u. A more
interesting value, from the network operator’s viewpoint, is the ability to keep
the voltage at the PCC above 0.9 p.u. The minimum reactive power input
needed to fulfil this requirement is then
Qin =
0.92 − 0.9 E
.
Xs
(4-3)
From (4-3) it can be seen that the possibility to keep the voltage at 0.9 p.u. is
easier, not only since the voltage level demand is lower, but also because the
needed input reactive power is relatively lower.
22
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A VSC has limited capacity of injecting reactive power into the grid. The basic
limitation is the current limit of the convertor. As a result, the reactive-power
capacity decreases with increasing active-power injection.
4.2
Compensation of load changes
A direct benefit of the utilization of a VSC-HVDC WP actively interfaced to the
grid is the compensation of local load changes, which offers improved grid
dynamics. An increase in the load will cause a high current flow, resulting in a
drop of the voltage along the line or cable connecting the load. The decrease
in voltage amplitude due to the load change is affected by several factors,
such as the size of the load, the length and impedance of the feeder and the
stiffness of the grid. The capabilities of the front-end VSC, of the WP, to
compensate for the load changes are studied.
In Fig. 3.1 a layout of the system model used in the study is shown. The load
connected at the PCC is increased in a step from 0.25 p.u. to 0.75 p.u. (cos φ
= 0.97 lagging) at t = 0.6 s (the base values for the per-unit calculations are
given in Appendix). The voltage at the PCC is studied for some different
configurations of the feeder.
First an overhead line feeder is considered with an X/R ratio of 5 and a feeder
reactance of 0.1 p.u. The WP is injecting 0.5 p.u. of active power into the
PCC. The voltage amplitude at the PCC is shown in Fig. 4.1 and the power
flow from the WP is plotted in Fig. 4.2. In Fig. 4.3 and Fig. 4.4, the voltage is
plotted for Xs = 0.2 p.u. Compared to the situation in Fig. 4.1 and Fig. 4.2, the
feeder resistance is now higher, thus the same load results in a higher voltage
drop over the feeder, but the voltage drop can be compensated with the same
amount of reactive power. In both situations the WP is able to retain the
voltage at 1 p.u.
The ability to control the voltage is different for a feeder with lower X/R ratio,
e.g. a cable. A simulation is carried out for a feeder with an X/R ratio of 1.
Without voltage regulation, the higher resistance of the cable results in an
increased voltage at the PCC (1.02 p.u.) during light load operation due to the
active power injected from the WP. The X/R ratio is lower than that in the
previous simulations, thus the voltage drop over the feeder is higher for the
same loadings. Also more reactive power is needed to compensate for the
voltage drop. In Fig. 4.5 and Fig. 4.6 the feeder reactance is 0.1 p.u. and in
Fig. 4.7 and Fig. 4.8 the reactance is 0.2 p.u. Still, the WP is able to retain the
voltage at the PCC at 1 p.u., but with the lower X/R ratio the amount of
reactive power needed is bigger.
23
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Voltage at PCC when local load change.
1.04
Voltage regulation
1.03
No voltage regulation
1.02
1.01
Line voltage [p.u.]
1
0.99
0.98
0.97
0.96
0.95
0.94
0.93
0.92
0
0.2
0.4
0.6
0.8
1
Time [s]
1.2
1.4
1.6
1.8
2
Fig. 4.1. Voltage amplitude at the PCC for overhead line feeder with X/R ratio 5 and Xs
= 0.1 p.u. with and without voltage regulation from the VSC. At t=0.6 s: a step in the
load from 0.25 p.u. to 0.75 p.u.
Power flow from WP when local load change.
1
P, voltage regulation
0.9
Q, voltage regulation
0.8
P, no voltage regulation
0.7
Q, no voltage regulation
0.6
Power [p.u.]
0.5
0.4
0.3
0.2
0.1
0.0
-0.1
-0.2
-0.3
0
0.2
0.4
0.6
0.8
1
Time [s]
1.2
1.4
1.6
1.8
2
Fig. 4.2. Power flow from the WP for overhead line feeder with X/R ratio 5 and Xs = 0.1
p.u. with and without voltage regulation from the VSC. At t=0.6 s: a step in the load
from 0.25 p.u. to 0.75 p.u.
24
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Voltage at PCC when local load change.
1.04
Voltage regulation
1.03
No voltage regulation
1.02
1.01
Line voltage [p.u.]
1
0.99
0.98
0.97
0.96
0.95
0.94
0.93
0.92
0
0.2
0.4
0.6
0.8
1
Time [s]
1.2
1.4
1.6
1.8
2
Fig. 4.3. Voltage amplitude at the PCC for overhead line feeder with X/R ratio 5 and Xs
= 0.2 p.u. with and without voltage regulation from the VSC. At t=0.6 s: a step in the
load from 0.25 p.u. to 0.75 p.u.
Power flow from WP when local load change.
1
P, voltage regulation
0.9
Q, voltage regulation
0.8
P, no voltage regulation
0.7
Q, no voltage regulation
0.6
Power [p.u.]
0.5
0.4
0.3
0.2
0.1
0.0
-0.1
-0.2
-0.3
0
0.2
0.4
0.6
0.8
1
Time [s]
1.2
1.4
1.6
1.8
2
Fig. 4.4. Power flow from the WP for overhead line feeder with X/R ratio 5 and Xs = 0.2
p.u. with and without voltage regulation from the VSC. At t=0.6 s: a step in the load
from 0.25 p.u. to 0.75 p.u.
25
ELFORSK
Voltage at PCC when local load change.
1.04
Voltage regulation
1.03
No voltage regulation
1.02
1.01
Line voltage [p.u.]
1
0.99
0.98
0.97
0.96
0.95
0.94
0.93
0.92
0
0.2
0.4
0.6
0.8
1
Time [s]
1.2
1.4
1.6
1.8
2
Fig. 4.5. Voltage at the PCC for cable feeder with X/R ratio 1 and Xs = 0.1 p.u. with and
without voltage regulation from the VSC. At t=0.6 s: a step in the load from 0.25 p.u.
to 0.75 p.u.
Power flow from WP when local load change.
1
P, voltage regulation
0.9
Q, voltage regulation
0.8
P, no voltage regulation
0.7
Q, no voltage regulation
0.6
Power [p.u.]
0.5
0.4
0.3
0.2
0.1
0.0
-0.1
-0.2
-0.3
0
0.2
0.4
0.6
0.8
1
Time [s]
1.2
1.4
1.6
1.8
2
Fig. 4.6. Power flow from the WP for cable feeder with X/R ratio 1 and Xs = 0.1 p.u.
with and without voltage regulation from the VSC. At t=0.6 s: a step in the load from
0.25 p.u. to 0.75 p.u.
26
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Voltage at PCC when local load change.
1.06
Voltage regulation
1.04
No voltage regulation
Line voltage [p.u.]
1.02
1
0.98
0.96
0.94
0.92
0.9
0
0.2
0.4
0.6
0.8
1
Time [s]
1.2
1.4
1.6
1.8
2
Fig. 4.7. Voltage at the PCC for cable feeder with X/R ratio 1 and Xs = 0.2 p.u. with and
without voltage regulation from the VSC. At t=0.6 s: a step in the load from 0.25 p.u.
to 0.75 p.u.
Power flow from WP when local load change.
1
P, voltage regulation
0.9
Q, voltage regulation
0.8
P, no voltage regulation
0.7
Q, no voltage regulation
0.6
Power [p.u.]
0.5
0.4
0.3
0.2
0.1
0.0
-0.1
-0.2
-0.3
0
0.2
0.4
0.6
0.8
1
Time [s]
1.2
1.4
1.6
1.8
2
Fig. 4.8. Power flow from the WP for cable feeder with X/R ratio 1 and Xs = 0.2 p.u.
with and without voltage regulation from the VSC. At t=0.6 s: a step in the load from
0.25 p.u. to 0.75 p.u.
27
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4.3
Compensation of voltage dips in the grid
A fault somewhere in the transmission network will cause a large current to
flow into the fault until it is cleared (typically in the range of 50–500 ms). The
fault current will result in a decrease in the voltage magnitude in a large area
of the network. This temporary decrease in the voltage is called a voltage dip
or sag. For locations close to the fault the voltage dip can be very large,
resulting in tripping of safety systems and production stops. The VSC-HVDC
WP can, by injecting reactive current, minimize the voltage drops due to the
dips, and some production stops could be avoided.
Single wind power generators or WP installations are set to trip if the voltage
at the connection point is too low due to their own operational and security
demands. A VSC-HVDC WP installation that is able to keep up the voltage at
the PCC will therefore contribute to an uninterrupted operation of other WP
installations in the local area.
The voltage dips can be of different types, three-phase, two-phase, twophase-to-ground or single-phase-to-ground, where all but three-phase faults
will result in unbalanced dips. Mitigation of these unbalanced dips is possible
through the implementation of the VSC controller in both the positive and the
negative sequence frames. More details can be found in [28].
The main difference between the phenomena of the voltage dips and
switching on of the local loads, from the voltage regulator point of view, is the
time duration and the amplitude of the voltage decrease. Voltage dips could
last for shorter duration, which might be shorter than the time constant of the
voltage regulator resulting in uncompensated dips. This is, however, a design
issue regarding the sensitivity of the WP and local grid loads as related to the
dip duration. More intriguing is that voltage dips could have small amplitude
(or remaining voltage), which might require a high current to compensate for
the dip, resulting in hitting the current limit of the VSC controller. This means
that a decreased remaining voltage at the PCC will last for, possibly, long
duration and might lead to tripping of the generating units or local loads.
The voltage control operation of the VSC, using the two current limitation
methods depicted in Fig. 3.5, is then evaluated. The simplified system that is
shown in Fig. 3.1 is considered. A voltage dip of 0.5 p.u. remaining magnitude
is applied at the remote bus R from 0.5 s to 0.7 s. The feeder has an X/R ratio
of 10, with Xs = 0.84 p.u., the local loads are 0.3 p.u. with 0.9 power factor
lagging voltage-independent loads, and the active power production of the WP
is 0.6 p.u. Note that a decreased value of active power generation is assumed
here in order to allow the injection of reactive power into the grid and
emphasize the need for active power control even in this case. Updating Fig.
3.5 to Fig. 4.9, the injected active power results in an active current
component “a” that allows for a maximum reactive current injection of “af”,
according to the operational requirement, without reaching the current limit.
28
Reactive current
ELFORSK
Maximum current
amplitude
L2
d
b
e
L1
c
f
a
x
Active current
Fig. 4.9 Active and reactive currents with reduced active power injection from the WP.
The amplitude of the voltages at the remote bus (R) and the local bus (PCC)
are shown in Fig. 4.10. The PCC voltage during the dip is not fully regulated
since the injected WP current has hit the limit due to the increased injected
reactive current. As shown in Fig. 4.11, the reactive current is limited,
according to the current limit algorithm L1, at about 0.6 s, at which the PCC
voltage starts attaining a constant value that is lower than 0.9 p.u. The
injected active current is kept constant, before and after the dip, apart from
the transients due to the coupling between the d- and q-components of the
current vector.
Fig. 4.10. Voltage at the connection point PCC (solid), and the remote bus (dashed);
with the current limitation L1.
29
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Fig. 4.11. Injected VSC currents; active current (black solid) and reactive current (red
dashed); with current limitation L1.
Using the second current limitation algorithm L2, the voltage at the PCC
during the dip period reaches a higher value, as shown in Fig. 4.12. This is
because the injected active current is decreased, when the current limit is hit,
allowing more reactive current to be injected, as shown in Fig. 4.13.
Fig. 4.12. Voltage at the connection point PCC (solid), and the remote bus (dashed);
with current limitation L2.
30
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Fig. 4.13. Injected VSC currents; active current (black solid) and reactive current (red
dashed); with current limitation L2.
4.4
Voltage fluctuations causing flicker
Certain fluctuations in the voltage can cause light flicker, light intensity
fluctuations that are observable and/or irritable to a human observer. Possible
sources of such voltage fluctuations are [29]
•
Rolling mills
•
Large industrial motors with variable loads
•
Arc furnaces
•
Saw mills
•
Switching of power-factor correction capacitors
•
Start-up of drives and step load changes of drives
•
Connection and disconnection of lines
Loads causing flicker can do this by either provoking separate voltage
changes (flicker due to repetitive events) or by provoking voltage fluctuations
(flicker due to fast current variations). An important load of the latter type is
the arc furnace in which metal is melted using a high electric current. The
furnace takes large amounts of power and causes flicker over a large area
since it is often connected to the transmission grid.
A way to measure the level of flicker from a voltage measurement is
explained in the flickermeter standard, IEC 61000-4-15, for which the
31
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different steps are presented in Fig. 4.14. As input is used a voltage waveform
(with a sample rate of at least 400 Hz over 10 minutes). For an instantaneous
flicker sensation (e) that exceeds one, more than half of the observers will
notice a flickering of the light. To characterize the severity of the voltage
fluctuation the statistical analysis in block 5 is done. The outputs are values
for the short- and long-term flicker severity, PST and PLT. The short-term
flicker severity is calculated from the probability distribution function of the
instantaneous flicker sensation over a 10-minute interval. The long-term
flicker severity is calculated from 12 consecutive values of the short-term
flicker severity. A PST value higher than one indicates that more than 95 % of
the observers will consider the flicker as disturbing.
Fig. 4.14. Standard flickermeter according to IEC 61000-4-15 [29].
In this study the PST is chosen as a measure for the voltage fluctuations at the
PCC and the ability of the VSC-HVDC WP to mitigate or lower the voltage
fluctuations by controlling the reactive power input from the WP.
A recorded three-phase waveform at an arc furnace connection point is used
and imposed as the voltage source at bus R, as designated in Fig. 3.1. A
snapshot of the remote voltage is shown in Fig. 4.15.
32
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1
Remote bus voltage [p.u.]
0.5
0
-0.5
-1
0.4
0.5
0.6
Time [s]
0.7
0.8
Fig. 4.15. Measured data of the voltage at an arc furnace connection point.
In Fig. 4.16, the rms PCC-voltage at 230 V level is shown for the noncontrolled situation. The simulation is done using a recording with a length of
6 seconds. According to the flickermeter standard the PST should be calculated
over a measurement period of 10 minutes. The use of a shorter recording
may affect the contribution of lower frequencies, but since the absolute value
is of less interest and only used here for the comparison, this is seen as a
valid approach.
The uncontrolled voltage results in a PST of 3.2. When controlling the voltage
at the PCC by injecting reactive power some of the voltage fluctuations can be
damped. The result is seen in Fig. 4.16. Mainly fluctuations of lower
frequencies are affected since the voltage control is relatively slow. The
obtained PST value is 2.8, which indicates an improvement of about 13 % of
the flicker severity. It can be concluded also that for voltage fluctuations that
are mainly low in frequency the reactive power control could show a better
result.
33
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Voltage during flicker.
250
245
Phase voltage [V]
240
235
230
225
220
215
210
0
0.5
1
1.5
2
2.5
3
Time [s]
3.5
4
4.5
5
5.5
6
Fig. 4.16. Scaled PCC voltage with fluctuating grid loads; no reactive-power control.
(PST value is 3.2.)
Voltage during flicker.
250
245
Phase voltage [V]
240
235
230
225
220
215
210
0
0.5
1
1.5
2
2.5
3
Time [s]
3.5
4
4.5
5
5.5
6
Fig. 4.17. Scaled PCC voltage with fluctuating grid loads; with reactive-power control.
(PST value is 2.8.)
34
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4.5
Impact of harmonics
Electric loads with nonlinear voltage/current behaviour cause voltage
harmonics at its connection point to the grid. Such loads can be diode
rectifiers, which are common in electronic equipment. The VSC-HVDC WP
ability to suppress voltage harmonics at the PCC is investigated with
simulations. The simulation model is shown in Fig. 3.1.
A three-phase full-bridge rectifier is connected to the PCC with three different
resistive load sizes, 0.25, 0.5 and 0.75 p.u. This kind of load will mainly cause
current harmonics of order 5, 7, 11, 13, … with descending amplitudes (even
and triplet harmonics are small) and thus the voltage at the PCC will contain
harmonics of the same orders. The level of distortion of the voltage is
dependent on the relation between the load size and the source impedance.
Since different harmonics will affect both the negative and positive sequence
differently, an error could appear in the estimated grid voltage angle [32]
causing degraded voltage regulation. By decomposing the voltage into
positive and negative sequence components (in the αβ-frame), a better
estimation, using the PLL as shown in Fig. 4.18, is achieved. This
decomposition is done using a delayed signal cancellation algorithm (DSC)
[33], where the positive sequence component of the voltage is calculated as
1⎛
⎛ T ⎞⎞
uαβp (t ) = ⎜⎜ uαβ (t ) + uαβ ⎜ t − ⎟ ⎟⎟ ,
2⎝
4 ⎠⎠
⎝
(4-4)
where T is period at the fundamental frequency, and used as an input to the
PLL.
uabc
abc
uabp
uab
ab
DSC
Q-PLL
^
w
^
f
Fig. 4.18 Operation of the PLL using positive sequence voltage.
It can be analyzed how a harmonic content in the voltage will appear in the
vector uαβp as done in [28]. A voltage with harmonic content can be described
in the αβ-frame as
uαβ (t ) = U1e jωt + U h e( hs ) jhωt ,
(4-5)
with the first term describing the fundamental component and the second
term the harmonic content, h indicates the harmonic order and hs indicates the
sequence of the harmonic as
⎧+ 1
⎪
hs = ⎨− 1
⎪0
⎩
h = 3n + 1
h = 3n + 2, n = 0, 1, 2,K
h = 3n
35
(4-6)
ELFORSK
By substituting (4-5) into (4-4) to achieve the positive sequence component
of the voltage the following expression for the harmonic content in the voltage
is found:
Uh
(cos(hωt ) + j (hs ) sin(hωt ))
2
.
Uh ⎛ ⎛
π⎞
π ⎞⎞
⎛
+ j ⎜⎜ cos⎜ hωt − h ⎟ − (hs ) sin ⎜ hωt − h ⎟ ⎟⎟
2 ⎝ ⎝
2⎠
2 ⎠⎠
⎝
h
uαβ
p (t ) =
(4-7)
It is shown that harmonics of order 5 and 7 will be cancelled out and not
appear in uαβp (this also holds for the 17th and 19th harmonic). The amplitude
of the 11th and 13th harmonic is not affected and will appear with the same
amplitude. Triplet harmonics appear with their amplitudes decreased by a
factor of 2. Since the three-phase bridge rectifier will inject harmonics of
order 5, 7, 11 and 13 (plus higher orders) it can be expected that a controller
equipped with this PLL will give a much improved estimation of the voltage
angle θ compared to a PLL without the DSC (an input to the PLL that only
contains the fundamental component would of course be ideal). An accurate
estimation of θ is important to achieve a good control of the voltage and also
mitigating harmonic distortion in the voltage.
In IEC 61000-3-6 indicative values for planning levels are given considering
the harmonic voltage [30]. Values are given for both MV (medium voltage)
and HV-EHV (high voltage, extra high voltage). These are only indicative
values but can be used in comparison to the obtained values from the
simulations.
Table 4-1. Indicative planning levels for harmonic voltages (in percent of the
fundamental voltage) [30].
Harmonic order
[h]
2
3
4
5
6
7
8
9
11
13
15
THD
Harmonic voltage
at MV [%]
1.8
4
1
5
0.5
4
0.5
1.2
3
2.5
0.3
6.5%
Harmonic voltage
at HV-EHV [%]
1.4
2
0.8
2
0.4
2
0.4
1
1.5
1.5
0.3
3%
4.5.1 Local harmonics-generating load
In this subsection simulations are presented with the load connected at the
PCC.
36
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In Fig. 4.19, Fig. 4.21 and Fig. 4.23 the voltage waveform at the PCC is
shown for loads of 0.25, 0.5 and 0.75 p.u. respectively, with and without
voltage regulator. In Fig. 4.20, Fig. 4.22 and Fig. 4.24 are shown the
corresponding voltage harmonics spectrum at the PCC. The unregulated
voltage contains harmonics of order 5, 7, 11, 13 and higher as noted earlier.
With voltage regulation the 5th harmonic is suppressed (more for a lower load)
but the ability to suppress the 7th harmonic is poor, for a low load the content
is even increased. Harmonics of order 11, 13 and higher are difficult to
suppress due to limitations of the regulator. The total harmonic distortion
values (THD) for the above various cases are reported in Table 4-2.
It should be noted that the settings and bandwidth of the voltage regulator
are critical to the ability to suppress the harmonic content. The setting used is
optimized for a load of 0.75 p.u.
Voltage waveform at PCC
1.2
Without voltage regulator
1.0
With voltage regulator
0.8
Phase voltage at PCC [p.u.]
0.6
0.4
0.2
0.0
-0.2
-0.4
-0.6
-0.8
-1
-1.2
0
2
4
6
8
10
Time [ms]
12
14
16
18
20
Fig. 4.19. Voltage waveform at the PCC for a load of 0.25 p.u.
37
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Voltage harmonics at PCC
12
11
10
Percentage of fundamental
9
8
7
6
5
4
3
2
1
0
3
5
7
9
Harmonic order
11
13
15
Fig. 4.20. Voltage harmonics at the PCC for a load of 0.25 p.u. Without voltage
regulator to the left (blue) and with voltage regulator to the right (red).
Voltage waveform at PCC
1.2
Without voltage regulator
1.0
With voltage regulator
0.8
Phase voltage at PCC [p.u.]
0.6
0.4
0.2
0.0
-0.2
-0.4
-0.6
-0.8
-1
-1.2
0
2
4
6
8
10
Time [ms]
12
14
16
18
20
Fig. 4.21. Voltage waveform at the PCC for a load of 0.5 p.u.
38
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Voltage harmonics at PCC
12
11
10
Percentage of fundamental
9
8
7
6
5
4
3
2
1
0
3
5
7
9
Harmonic order
11
13
15
Fig. 4.22. Voltage harmonics at the PCC for a load of 0.5 p.u. Without voltage
regulator to the left (blue) and with voltage regulator to the right (red).
Voltage waveform at PCC
1.2
Without voltage regulator
1.0
With voltage regulator
0.8
Phase voltage at PCC [p.u.]
0.6
0.4
0.2
0.0
-0.2
-0.4
-0.6
-0.8
-1
-1.2
0
2
4
6
8
10
Time [ms]
12
14
16
18
20
Fig. 4.23. Voltage waveform at the PCC for a load of 0.75 p.u.
39
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Voltage harmonics at PCC
12
11
10
Percentage of fundamental
9
8
7
6
5
4
3
2
1
0
3
5
7
9
Harmonic order
11
13
15
Fig. 4.24. Voltage harmonics at the PCC for a load of 0.75 p.u. Without voltage
regulator to the left (blue) and with voltage regulator to the right (red).
Table 4-2 Total harmonic distortion (THD) with various local load levels.
Local load [p.u.]
0.25
0.5
0.75
THD with no-regulation
[%]
6.1
9.1
11.7
THD with voltage
regulation [%]
5.9
5.4
6.4
4.5.2 Upstream harmonics-generating load
In this subsection simulations are presented with the load connected at the
grid. The ability of the WP to compensate for the resulting voltage harmonics
at the PCC is studied.
In Fig. 4.25, Fig. 4.27 and Fig. 4.29 the voltage waveform at the PCC is
shown for loads, placed at the grid connection, of 0.25, 0.5 and 0.75 p.u.
respectively. In Fig. 4.26, Fig. 4.28 and Fig. 4.30 are shown the
corresponding voltage harmonics spectrum at the PCC. The unregulated
voltage contains harmonics mainly of order 5 and 7. With voltage regulation
the 5th harmonic is marginally affected and the 7th harmonic is even increased
(up to 450 % for the 0.75 p.u. load). The total harmonic distortion values
(THD) for the above various cases are reported in Table 4-3.
40
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Voltage waveform at PCC
1.2
Without voltage regulator
1.0
With voltage regulator
0.8
Phase voltage at PCC [p.u.]
0.6
0.4
0.2
0.0
-0.2
-0.4
-0.6
-0.8
-1
-1.2
0
2
4
6
8
10
Time [ms]
12
14
16
18
20
Fig. 4.25. Voltage waveform at the PCC for a load of 0.25 p.u.
Voltage harmonics at PCC
12
11
10
Percentage of fundamental
9
8
7
6
5
4
3
2
1
0
3
5
7
9
Harmonic order
11
13
15
Fig. 4.26. Voltage harmonics at the PCC for a load of 0.25 p.u. Without voltage
regulator to the left (blue) and with voltage regulator to the right (red).
41
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Voltage waveform at PCC
1.2
Without voltage regulator
1.0
With voltage regulator
0.8
Phase voltage at PCC [p.u.]
0.6
0.4
0.2
0.0
-0.2
-0.4
-0.6
-0.8
-1
-1.2
0
2
4
6
8
10
Time [ms]
12
14
16
18
20
Fig. 4.27. Voltage waveform at the PCC for a load of 0.5 p.u.
Voltage harmonics at PCC
12
11
10
Percentage of fundamental
9
8
7
6
5
4
3
2
1
0
3
5
7
9
Harmonic order
11
13
15
Fig. 4.28. Voltage harmonics at the PCC for a load of 0.5 p.u. Without voltage
regulator to the left (blue) and with voltage regulator to the right (red).
42
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Voltage waveform at PCC
1.2
Without voltage regulator
1.0
With voltage regulator
0.8
Phase voltage at PCC [p.u.]
0.6
0.4
0.2
0.0
-0.2
-0.4
-0.6
-0.8
-1
-1.2
0
2
4
6
8
10
Time [ms]
12
14
16
18
20
Fig. 4.29. Voltage waveform at the PCC for a load of 0.75 p.u.
Voltage harmonics at PCC
12
11
10
Percentage of fundamental
9
8
7
6
5
4
3
2
1
0
3
5
7
9
Harmonic order
11
13
15
Fig. 4.30. Voltage harmonics at the PCC for a load of 0.75 p.u. Without voltage
regulator to the left (blue) and with voltage regulator to the right (red).
43
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Table 4-3 Total harmonic distortion (THD) with various grid load levels.
Grid load [p.u.]
0.25
0.5
0.75
4.6
THD with no-regulation
[%]
1.8
2.8
3.8
THD with voltage
regulation [%]
6
9
11.3
Conclusions
In this chapter the ability to mitigate some power quality problems using
reactive power control was described. It was first shown that control of the
voltage at the PCC requires an inductive network, as seen from the WP.
The situation with a drop in the voltage at the PCC due to a step change in
the local load was first considered. Simulations on some different feeder
parameters were performed to study the ability of the WP to retain the
voltage at the PCC at 1 p.u. Given a network with a big enough reactance this
is possible. When the current limit is hit, the mitigation is slowed down.
The ability to keep the voltage at 1 p.u. during a voltage dip was studied
using the two different current limiting algorithms, L1 and L2. L2 showed an
improved ability compared to L1. By decreasing the active power input a
wider control range using reactive power was achieved.
A recording of the voltage at the connection point of an arc furnace was used
to study the ability to mitigate voltage fluctuations leading to flicker. The
fluctuations occur in a wide frequency range and the ability to mitigate fast
fluctuations with reactive power control is poor. Slower fluctuations, on the
other hand, can be damped to some extent. The PST value at the PCC was
reduced by 13 %.
The final power quality issue that was simulated was harmonics, both
generated at the PCC and from an upstream grid load. Harmonics occur at a
timescale smaller than the fundamental period, hence requiring a very fast
control system. The reactive power control is too slow to mitigate the
harmonics, but for both the local and grid load the 5th harmonic is decreased.
For a grid load the 7th harmonic is increased considerably for a high load.
We can thus conclude that reactive power control is effective for an inductive
network. The current handling capability of the VSC limits the control range
and by decreasing the active power input a larger control range is obtained.
The reactive power control has the ability to mitigate power quality problems
that are not to fast, i.e. load changes and dips. For faster phenomena it
shows a limited effect. This is because the bandwidth of the controller must
be limited to avoid an unstable system.
44
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5
Active power control of HVDC wind
park — DC-link solutions
In the previous chapter the ability to mitigate the power quality problems by
using only reactive power control has been investigated. In this chapter, the
control of the active power will also be considered. In order to provide this
capability, the power flow from the DC-link is to be controlled. The various
techniques that could be implemented in order to accomplish this
controllability are studied here. The ability to control the active power flow
increases the voltage dips ride through capability of the VSC-HVDC WP in case
of an upstream fault [36], and could also contribute to the mitigation of
various power quality problems at the local grid, as it will be investigated in
the next chapter.
5.1
Task definition
Since wind power and grid loads are uncorrelated in time, this requires large
amounts of balancing power basically for frequency control and stabilization.
The front-end VSC of HVDC-WP is able to both consume and produce reactive
power but not active power. The DC power flowing into the VSC will also flow
into the grid as active power (with exception of some losses). By controlling
this power flow to the grid, the following tasks are possible:
•
Contributing to system protection/security
Generally the production of active power from the WP is kept as high as
possible. On most wind turbines the pitch angle of the blades are controllable
and thereby the amount of wind power that is converted to active electric
power at a certain wind speed can be adjusted. The time response for the
pitch angle is not very fast (a few seconds) but the method offers a way of
varying the active power input. Due to the slow response of the pitch angle
control it cannot be used to mitigate phenomena within a time-scale less than
a few seconds occurring at the PCC. However, it can contribute to system
security/protection measures, which are usually required within a predefined
time that complies with the time response of the WP.
For large-scale wind parks, it is required by the grid operator that the active
power injection to the grid be controllable by remote signals [34][35]. It is
also required that the WP production can be reduced to 20 % of rated power
in less than 5 s without the disconnection of the individual wind turbines. The
details of the WP controller will not be studied here, however, it will be
assumed that the WP has the ability to comply with the grid codes in this
regard.
•
Coping with grid codes
Besides the above-mentioned operational requirements there are a number of
power quality immunity requirements that the WP should comply with.
Generally, the WP must be able to continue in operation during and after
disturbances in the transmission network. The ride-through capability in case
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PCC voltage [p.u.]
of a fault at the transmission grid is described by Fig. 5.1 (according to
[34][35]), where the slope of the recovery line (after 0.25 s) depends on the
characteristics of the WP.
1.0
0.9
0.25
0.0
0.25
Time [s.]
Fig. 5.1. SvK and Nordel grid code for large-scale WP ride-through requirement.
Such a dip at the PCC will cause increased currents to be injected by the WP.
Regarding the VSC-HVDC WP configuration, the VSC should be oversized in
order to withstand such a condition [36]. Another way is to instantly reduce
the injected active power, which will require a fast control over the power flow
from the WP. For this purpose, a DC current chopper is introduced in the
following section.
•
Providing ancillary services
This is investigated in this work (next chapter) using the voltage regulation
capability of the VSC along with a DC link configuration that provides the
capability to control both the active and reactive power. It has been shown
before, referring to Fig. 3.6 and Fig. 4.12, that the ability to reduce the active
injected current of the WP results in providing better voltage-dips
compensation capability. It is to be more investigated if other voltage quality
phenomena, such as voltage amplitude variation and voltage harmonics,
could be better mitigated with the implementation of active power control
along with the reactive power controller.
To use the active power control to mitigate fast transient problems at the
PCC, there is a need for faster system. A solution could be to use an energy
storage device or dump load with a fast time response. An energy storage
device could be used to both inject and consume active power and thus
contribute to a temporary higher demand from the grid or compensate for a
temporary decrease in production as well as store excessive power. A load
dump can only consume excessive power.
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The control of active power can also be accomplished by combining two or
three different methods with different time constants, as shown by Fig. 5.2.
The first step could be to control the active power flow by using a fast dump
load (using a DC current chopper as proposed here), then by using a slower
storage device and finally by changing the control commands at the WP
(through torque control or pitch angle control). Thus, a fast response can be
achieved but mitigation is not limited to transient problems.
Grid voltagequality phenomena
Transients
corrective measures
Reactive power
controller
Grid security
measures
Active power
controller
time/
energy
limit
Chopper
control
Storage
control
time/
energy
limit
WP
control
Fig. 5.2. Combined Active/reactive power control chart.
5.2
Chopper control
A simple way to consume excessive active power is to shunt it into a resistive
element that is implemented in the DC-link. The energy is dissipated as heat,
and this puts limits on both instantaneous power and the energy capability.
The resistance can be connected and disconnected using power transistors or
thyristors. Using a resistance, however, does not provide the capability of
injecting oscillating active power that can be advantageous in mitigating any
oscillations of the active power at the utility grid. In order to provide such a
capability, an inductor should be implemented instead of the resistance in
order to utilize an LC oscillating circuit. We will refer to such a circuit as “DC
current chopper”. The exact design of this circuit, however, is not detailed
here rather the control and the energy requirements of it which could be met
through various designs.
The DC current chopper is shown in Fig. 5.3. It is connected in parallel with
the DC-link capacitor Cdc. The chopper is used to regulate the DC-voltage by
47
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holding the current difference (ΔI) between the primary source current Iin and
the current to be injected into the grid idc using the open loop controller shown
in Fig. 5.4. The chopper introduces an additional control variable, which
provides more flexibility and control opportunities.
DC-link
Chopper
Iin
DI
udc
idc
PCC
AC-filter TR
vsc
Cdc inverter
Utility
Grid
Fig. 5.3. DC-link with a current chopper.
udc
+
Dudc
-
*
PI-controller
chopper switch
Comparator control signal
iL
iL
*
u dc
Fig. 5.4. DC-chopper control.
* that is
The chopper controller produces a chopper current reference iL
proportional to the difference between the DC-link voltage and its reference.
The chopper current reference is then compared with the actual current to
either switch on or off the chopper.
The difference between the input current and the average value of the output
current, which represents the average value of the chopper current (∆I),
should be small, since the amplitude of the chopper current oscillations
depends on it in the way that less ∆I results in lower oscillations in the
chopper current and hence in the DC-link voltage. Moreover, the maximum of
the output current (idc) should be less than (or equal to) the input current.
Accordingly, ∆I is set here to 20 % of the input current (∆I = 0.2Iin). This value
of ∆I allows 20 % peak value of injected current oscillations into the grid. The
injected DC current (hence the active current reference) is:
idc = 0.8I in + ir .
(5-1)
where ir is the ripple current (in per unit) that depends on the oscillations at
the PCC voltage and is calculated in the controller as:
u
ir = 1 − d* .
ud
(5-2)
The size of the capacitor is determined from the constraints on the maximum
allowable DC voltage ripple Δudc . A design expression of the capacitor size,
which is based on a simplified analysis of the instantaneous power flow, has
been used here [46]:
Cdc =
Sn
*
u dc Δu dc
⋅
1
2ω n
(5-3)
where Sn is the rated power of the VSC, and ωn is the fundamental angular
frequency at the grid.
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The operation of the DC-current chopper is tested in the next chapter when
operating towards a grid with loads that are causing voltage amplitude
variation at the PCC. If the limit set in (5-1) is violated due to increased
oscillations at the grid voltage, increased oscillations will also appear at the
DC-link. In this situation a further control (e.g. storage control) will be
activated in order to stabilize the system (e.g. by further lowering the input
power and hence Iin).
The idea behind using the chopper is the fast time response. However, for
better utilization of the power the storage control could also be considered.
5.3
Storage Control
In this section different means of storage control are described. The emphasis
is on the amount of stored energy and the power capabilities. The ability to
store energy in the DC-link would provide an even greater control range than
using the chopper alone, which has been introduced above.
The produced energy generated by the WP, in general, can be stored
electromagnetically, electrochemically, electromechanically, or as potential
energy. Each energy storage device usually needs one or more power
conversion units in order to adjust the energy to match its storage
requirements. Using VSC-HVDC WP installation, such units already exist and it
could be more economical to make use of them to reduce the total cost of the
storage. Moreover, utilizing the storage at the DC-link is more feasible if it is
installed at the inverter on-shore station.
The main focus here is on energy storage facilities at the DC-link, where the
main requirements are fast response, storage of fluctuating energy, adequate
size compared to the investment, and environmentally friendly technology.
5.3.1 SMES—Superconducting Magnetic Energy Storage
An SMES is a device that stores energy in the magnetic field generated by the
DC current flowing through a superconducting coil in solenoid or toroid
configuration. Since the energy is stored through circulating currents, energy
can be drawn or injected from an SMES with almost instantaneous response
and high efficiency. The energy can be stored or delivered over periods
ranging from milliseconds to several hours [39]. Hence an SMES is
appropriate for use for power system conditioning applications [40].
Due to high costs, commercially available SMES systems generally only
provide a few seconds of stored energy. SMES for use in power systems
consists of both the inductor and a converter to serve as an interface between
the AC grid and the DC coil. Since the SMES in this study would be placed in
the HVDC-link, conversion between AC and DC is unnecessary and thus the
cost can significantly be reduced. However, the SMES operates at a low
voltage so some DC/DC converter is probably necessary [27]. The use of high
temperature superconductors should also make SMES cost effective due to
reduction in refrigeration needs [39].
It has been shown before that micro (<0.1 MWh) and midsize (0.1-200 MWh)
SMES with energy range 50-500 MJ could potentially be more economical for
49
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power transmission and distribution applications [39][42]. In [40], a SMES,
connected to the distribution network through a two-quadrant DC chopper
and an inverter, has been proposed to compensate for non-linear and
pulsating loads due to its fast time response. In [43], a benefit-by-cost
comparison between different storage systems for different cases has been
carried out. It has been found that SMES has the highest benefit-by-cost ratio
when connected near an industrial plant and used to improve the power
quality.
A SMES could be simply applied here by replacing the current chopper
inductor with a superconductor. However, SMES devices with such high
ratings are not yet commercially available.
5.3.2 Capacitors
Capacitors store energy by accumulating positive and negative charges on
plates separated by an insulating dielectric. They are often used for very
short-term storage in power converters. In dynamic voltage restorers (DVR),
capacitors with energy ratings of 1 MJ and power ratings of 2 MVA are used.
Additional capacitors can be added to the dc bus of motor drives and
consumer electronics in order to provide a capability to ride through voltage
dips [39].
Electric double layer capacitors, known as ultracapacitors or supercapacitors,
are emerging as energy storage devices capable of delivering large amount of
power over relatively short time. However, their low energy density makes
them unsuitable for use as primary energy storage in most systems.
5.3.3 BES—Battery Energy Storage
In BES the energy is stored in electrochemical form. Batteries are available in
several different types such as lead-acid, Nickel-Cadmium, Nickel-Metal
Hybrid, Lithium ion and Lithium polymer batteries. The available energy for
discharge and the charging energy both are limited by the chemical reaction
rate of the BES [43].
BES differ in energy density, lifetime, durability, cost, etc. They are typically
composed of smaller cells (each a few volts), and several batteries form larger
units by serial and parallel configurations. BES exists with power ratings of a
few MW and a storage capacity of some tens of MWh.
To connect a battery to the HVDC-link some DC/DC conversion is probably
needed [27]. Moreover, batteries provide a nearly constant voltage source,
which make them adequate for use as a source for a power conditioning
system. In other words, they are not adequate for use as power conditioning
systems themselves.
There are also environmental concerns related to BES due to toxic gas
generation during charge and discharge. Moreover, the recycling/disposal of
some kinds of BES is not yet very well established [39].
50
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5.4
Wind park control
As has been mentioned before the wind park controller is neither simulated
nor studied in details since it is not the focus in this work.
5.5
Conclusions
In this chapter the possibilities to control the active power injected from the
WP were discussed. The possible outcome of such an action has been also
described. With the active power control, large WPs would contribute to
system security, protection, and stabilization. They also not only comply with
the grid codes but also improve the local power quality and system dynamics.
A control hierarchy with different individual time-scales has been proposed in
Fig. 5.2 in order to achieve an active power control interface. Using a current
chopper at the inverter station of the HVDC WP will provide a fast control
response to counteract fast transient active power phenomena at the grid.
However, due to the physical limitation of the chopper, a storage device with
a slower time response could also be beneficial to activate if the problem at
the grid persists. A slower WP controller is considered essential to comply with
the grid codes, though it is not discussed here in details. Instead it has been
assumed that the input power from the WP can be reduced to 20% of its
maximum value in 5 s.
A design criterion for the current chopper has been also presented. A current
limit has been set in order to reduce the size of the chopper conductor.
However, if this current limit is violated then the storage control should be
activated in order to reduce further the input power. A comparison between
different storage devices that can be installed in the DC-link has been carried
out. It seems that the SMES (superconducting magnetic energy systems) is a
promising technology, though still expensive and not available in the market
for high ratings. The same applies also for supercapacitors. On the other hand
batteries are well established and can be connected together to serve for high
power ratings, though there are some environmental concerns due to toxic
gas generation during charge and discharge and also due to its
recycling/disposal techniques.
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6
Evaluation of combined active-andreactive power control using DClink solutions
The main aim of this chapter is to compare between the two cases of using
only reactive power control and combined active-reactive-power control. The
latter control requires extra investment in the system and hence it is
important to evaluate the benefits that could be eventually gained.
The benefits of adding the active power control capability, using the DC
current chopper or storage control that have been described in the previous
chapter, are examined through simulation using the same cases that have
been studied in Chapter 4.
6.1
Compensation of load changes
The ability to mitigate the voltage drop due to an increase in the local load is
examined when using only reactive power control and combined active-andreactive power control. The load instantaneously increases from 0.25 p.u. to
0.75 p.u. at t = 0.6 s. A cable feeder with X/R ratio of 1 and Xs of 0.2 p.u. has
been assumed. In Fig. 6.1 and Fig. 6.2, the voltage at the PCC and the power
flow from the VSC-HVDC front-end is plotted respectively. The WP is injecting
a constant value of 0.5 p.u. active power and during the load change the
storage device is injecting extra power to the VSC-HVDC front-end. The
maximum voltage drop is reduced but the settling time is a bit longer. As
more active power is injected during the voltage drop less reactive power is
required to keep up the voltage, as shown by the lower trace in Fig. 6.2.
As seen from Fig. 6.2 active power is injected, which implies that there must
be some storage available. Some demands on this storage can be seen from
the figure, where the needed energy can be estimated to be 0.3 p.u. with a
maximum power of 0.15 p.u. For a per unit base of 100 MW this would result
in 30 MJ/15 MW storage.
Regarding the current chopper that has been described in the previous
chapter, the chopper is capable of injecting energy of 0.03 p.u. with a
maximum power of 0.2 p.u. Regarding the above energy need, extra battery
storage might also be necessary if such an operation (shown in Fig. 6.1) is
required.
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Voltage at PCC when local load change.
1.04
Reactive and active regulation
1.03
Reactive regulation
1.02
1.01
Line voltage [p.u.]
1
0.99
0.98
0.97
0.96
0.95
0.94
0.93
0.92
0
0.2
0.4
0.6
0.8
1
Time [s]
1.2
1.4
1.6
1.8
2
Fig. 6.1. Voltage at PCC for cable feeder with X/R ratio 1 and Xs = 0.2 p.u., with
reactive power control (dashed red line) and active/reactive power control (solid blue
line). Compare also to Fig. 4.7.
Power flow from WP when local load change.
1
P, reactive and active regulation
0.9
Q, reactive and active regulation
0.8
P, reactive regulation
0.7
Q, reactive regulation
0.6
Power [p.u.]
0.5
0.4
0.3
0.2
0.1
0.0
-0.1
-0.2
-0.3
0
0.2
0.4
0.6
0.8
1
Time [s]
1.2
1.4
1.6
1.8
2
Fig. 6.2. Power flow from WP for cable feeder with X/R ratio 1 and Xs = 0.2 p.u., with
reactive power control (dashed lines) and active/reactive power control (solid lines).
Compare also to Fig. 4.8.
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6.2
Compensation of voltage dips in the grid
Voltage dips penetrating to the PCC are compensated mainly using the
reactive power control. However, as mentioned before, lower dips can lead to
a condition where the current limit is hit and so an attained decreased voltage
at the PCC may occur. It has been shown before, in Chapter 3, that using a
current limitation algorithm that allows the active current (and hence active
power) to decrease in order to maintain more reactive current (and hence
reactive power) results in better voltage dips compensation capability.
Referring to Fig. 3.6, Fig. 4.12, and Fig. 4.13, the use of the DC current
chopper is promoted in order to comply with the required fast response.
6.3
Compensation of voltage fluctuations causing flicker
The ability to mitigate voltage fluctuations is done by simulating a VSC-HVDC
with only reactive power control and comparing to one with both active and
reactive power control. In Section 4.4 it was shown that only reactive control
could lead to some improvements of the power quality at the PCC, but mainly
the slower fluctuations were mitigated. In Fig. 6.3 the voltage amplitude for a
customer connected to the PCC is shown when using only reactive power
control. The obtained PST value was 2.8 (for the uncontrolled situation, the PST
value was 3.2). In Fig. 6.4 both active and reactive power control is used. The
active power control is able to mitigate some of the faster fluctuations and the
PST value is reduced to 2.3, an improvement of 16 % compared to only using
reactive power control and 27 % compared to the uncontrolled situation.
In Fig. 6.5 the injected active power from the VSC-HVDC WP is plotted. The
power from the WP is held at a constant value of 0.5 p.u. and the fluctuations
around this value are due to the injection/consumption of the storage device
between the WP and the front-end. From this figure the demands on the
storage device can be estimated. An energy storage of 0.01 p.u. and a power
rating of 0.15 p.u. would suffice. For a per unit base of 100 MW this would
result in a 1 MJ/15 MW storage. Regarding the current chopper that has been
considered here using (5-1) and (5-3), the chopper is capable of injecting
energy of 0.03 p.u. with a maximum power of 0.2 p.u. Hence, the use of the
DC current chopper is promoted here in order to comply with both the energy
and the fast time response requirements.
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Voltage during flicker.
250
245
Phase voltage [V]
240
235
230
225
220
215
210
0
0.5
1
1.5
2
2.5
3
Time [s]
3.5
4
4.5
5
5.5
6
Fig. 6.3. Voltage fluctuations at PCC using only reactive power control. (PST value is
2.8.)
Voltage during flicker.
250
245
Phase voltage [V]
240
235
230
225
220
215
210
0
0.5
1
1.5
2
2.5
3
Time [s]
3.5
4
4.5
5
5.5
6
Fig. 6.4. Voltage fluctuations at PCC using combined active and reactive power control.
(PST value is 2.3)
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Injected active power during flicker.
0.7
0.65
Active power [p.u.]
0.6
0.55
0.5
0.45
0.4
0.35
0.3
0
0.5
1
1.5
2
2.5
3
Time [s]
3.5
4
4.5
5
5.5
6
Fig. 6.5. Injected active power from VSC-HVDC front-end using combined active and
reactive power control.
The active power control using the DC current chopper is then tested. A closer
snapshot of the voltage at PCC and the DC-link voltage is shown in Fig. 6.6
with only reactive power control. Both voltages are oscillating, where the
amplitude of the oscillation at the PCC is affected by both the oscillations at
the remote bus R, as designated in Fig. 3.1, where the voltage distortion load
is connected, and the feeder parameters (here X/R = 10 and Xs = 0.84 p.u.).
Since the DC input current in this case is not allowed to oscillate, the
oscillations of the PCC voltage penetrate to the DC-link as oscillations imposed
on its nominal voltage. Regarding a 0.05 p.u. allowed oscillation in the design
of the DC-link capacitance, the DC-link overvoltage protection might trip in
this case.
In the case of both the active power control (using the chopper) and the
reactive power control being implemented, better regulation of both the PCCvoltage and DC-link voltage is achieved as shown in Fig. 6.7.
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Fig. 6.6. Voltage amplitude at PCC (upper) and DC-link (lower) during a connection of
a load at the remote bus generating voltage amplitude variation; reactive power
control.
Fig. 6.7. Voltage amplitude at PCC (upper) and DC-link (lower) during a connection of
a load at the remote bus generating voltage amplitude variation; active/reactive power
control.
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6.4
Impact of harmonics
In Section 4.5 the ability of the WP to mitigate voltage harmonics at the PCC,
using reactive power control, was studied. For a local harmonics-generating
load some improvements were shown, whereas for the grid connected load a
considerable increase in the 7th harmonic was seen. In this section the
situation with reactive power control is compared to the situation when using
combined active and reactive power control.
6.4.1 Local harmonics-generating load
In Fig. 6.8, Fig. 6.10 and Fig. 6.12 the voltage waveform at the PCC is shown
for local loads of 0.25, 0.5 and 0.75 p.u. In Fig. 6.9, Fig. 6.11 and Fig. 6.13
the corresponding harmonic content is shown. The difference is marginal but
there is a tendency towards worsening the voltage quality when using both
active and reactive power control. The corresponding THD values are reported
in Table 6-1 for the two cases of only reactive power control and combined
active and reactive power control.
Voltage waveform at PCC
1.2
Rective power control
1.0
Reactive and active power control
0.8
Phase voltage at PCC [p.u.]
0.6
0.4
0.2
0.0
-0.2
-0.4
-0.6
-0.8
-1
-1.2
0
2
4
6
8
10
Time [ms]
12
14
16
18
20
Fig. 6.8. Voltage waveform at the PCC for a load of 0.25 p.u.
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Voltage harmonics at PCC
12
11
10
Percentage of fundamental
9
8
7
6
5
4
3
2
1
0
3
5
7
9
Harmonic order
11
13
15
Fig. 6.9. Voltage harmonics at the PCC for a load of 0.25 p.u. With reactive power
control to the left (blue) and with both reactive and active power control to the right
(red).
Voltage waveform at PCC
1.2
Rective power control
1.0
Reactive and active power control
0.8
Phase voltage at PCC [p.u.]
0.6
0.4
0.2
0.0
-0.2
-0.4
-0.6
-0.8
-1
-1.2
0
2
4
6
8
10
Time [ms]
12
14
16
18
20
Fig. 6.10. Voltage waveform at the PCC for a load of 0.5 p.u.
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Voltage harmonics at PCC
12
11
10
Percentage of fundamental
9
8
7
6
5
4
3
2
1
0
3
5
7
9
Harmonic order
11
13
15
Fig. 6.11. Voltage harmonics at the PCC for a load of 0.5 p.u. With reactive power
control to the left (blue) and with both reactive and active power control to the right
(red).
Voltage waveform at PCC
1.2
Rective power control
1.0
Reactive and active power control
0.8
Phase voltage at PCC [p.u.]
0.6
0.4
0.2
0.0
-0.2
-0.4
-0.6
-0.8
-1
-1.2
0
2
4
6
8
10
Time [ms]
12
14
16
18
20
Fig. 6.12. Voltage waveform at the PCC for a load of 0.75 p.u.
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Voltage harmonics at PCC
12
11
10
Percentage of fundamental
9
8
7
6
5
4
3
2
1
0
3
5
7
9
Harmonic order
11
13
15
Fig. 6.13. Voltage harmonics at the PCC for a load of 0.75 p.u. With reactive power
control to the left (blue) and with both reactive and active power control to the right
(red).
Table 6-1 Total harmonic distortion (THD) for local loads.
Local load [p.u.]
THD with reactive power
control [%]
0.25
0.5
0.75
5.9
5.4
6.4
THD with combined
active and reactive
power control [%]
7
6.3
6.5
6.4.2 Upstream harmonics-generating load
In Fig. 6.14, Fig. 6.16 and Fig. 6.18 the voltage waveform at the PCC is
shown for grid connected loads of 0.25, 0.5 and 0.75 p.u. In Fig. 6.15, Fig.
6.17 and Fig. 6.19 the corresponding harmonic content is shown. The use of
both active and reactive power control results in a considerable improvement
compared to using only reactive power control. Compared to the nonregulated situation the 5th order harmonic is lowered, whereas the 7th is
increased. The corresponding THD values are reported in Table 6-2 for the
two cases of only reactive power control and combined active and reactive
power control.
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Voltage waveform at PCC
1.2
Reactive power control
1.0
Reactive and active power control
0.8
Phase voltage at PCC [p.u.]
0.6
0.4
0.2
0.0
-0.2
-0.4
-0.6
-0.8
-1
-1.2
0
2
4
6
8
10
Time [ms]
12
14
16
18
20
Fig. 6.14. Voltage waveform at the PCC for a load of 0.25 p.u.
Voltage harmonics at PCC
12
11
10
Percentage of fundamental
9
8
7
6
5
4
3
2
1
0
3
5
7
9
Harmonic order
11
13
15
Fig. 6.15. Voltage harmonics at the PCC for a load of 0.25 p.u. With reactive power
control to the left (blue) and with both reactive and active power control to the right
(red).
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Voltage waveform at PCC
1.2
Reactive power control
1.0
Reactive and active power control
0.8
Phase voltage at PCC [p.u.]
0.6
0.4
0.2
0.0
-0.2
-0.4
-0.6
-0.8
-1
-1.2
0
2
4
6
8
10
Time [ms]
12
14
16
18
20
Fig. 6.16. Voltage waveform at the PCC for a load of 0.5 p.u.
Voltage harmonics at PCC
12
11
10
Percentage of fundamental
9
8
7
6
5
4
3
2
1
0
3
5
7
9
Harmonic order
11
13
15
Fig. 6.17. Voltage harmonics at the PCC for a load of 0.5 p.u. With reactive power
control to the left (blue) and with both reactive and active power control to the right
(red).
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Voltage waveform at PCC
1.2
Reactive power control
1.0
Reactive and active power control
0.8
Phase voltage at PCC [p.u.]
0.6
0.4
0.2
0.0
-0.2
-0.4
-0.6
-0.8
-1
-1.2
0
2
4
6
8
10
Time [ms]
12
14
16
18
20
Fig. 6.18. Voltage waveform at the PCC for a load of 0.75 p.u.
Voltage harmonics at PCC
12
11
10
Percentage of fundamental
9
8
7
6
5
4
3
2
1
0
3
5
7
9
Harmonic order
11
13
15
Fig. 6.19. Voltage harmonics at the PCC for a load of 0.75 p.u. With reactive power
control to the left (blue) and with both reactive and active power control to the right
(red).
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Table 6-2 Total harmonic distortion (THD) for grid loads.
6.5
Grid load [p.u.]
THD with reactive power
control [%]
0.25
0.5
0.75
6
9
11.3
THD with combined
active and reactive
power control [%]
2.7
3.5
3.8
Conclusions
The four different power quality issues studied in Chapter 4 using reactive
power control have been revised, now using combined active and reactive
power control. They mainly put different demands on the required active
control in terms of energy and power capability.
In mitigating voltage drop due to load changes the use of active power control
showed some improvement, but the need for energy storage could be
significant.
When mitigating voltage dips at the PCC the use of current limiting algorithm
L2 (see Section 3.2.1), that allows for the active power to be decreased in
order to allow for more reactive power without hitting the current limit,
showed good potential in minimizing the dip severity by just lowering the
active power injected. The use of the DC current chopper has been presented
here as a feasible solution in order to provide such a capability. As voltage
dips are of limited duration, the need for energy storage is limited.
Compared to the reactive power control, the use of both active and reactive
power control resulted in better mitigation of voltage fluctuations leading to
flicker. Fluctuations with higher frequencies could now be damped by using a
current chopper. The use of a DC current chopper has not only resulted in
regulated grid voltage at the connection point but also in better regulated DClink voltage. The latter results in less harmonic emission and reduced risk for
tripping of the dc link due to dc overvoltage or undervoltage.
For a harmonics-generating load at the PCC there is not much improvement
compared to using only reactive power control. For the upstream grid load the
use of only reactive power control resulted in a large increase of the 7th
harmonic. This effect is clearly damped when also controlling the active power
but the 7th harmonic is still somewhat larger than for the non-controlled
situation.
As a general rule, mitigation of slow phenomena requires larger amounts of
storage. Mitigation of (slow) voltage magnitude variations due to load
switching requires much more storage than mitigation of fast voltage
fluctuations and voltage dips. However, the mitigation of fast phenomena
requires a fast controller. The speed of the controller is however limited as a
too fast controller could result in instable behavior of the system. Therefore,
the ability of the controller to mitigate very fast voltage fluctuations and
voltage harmonics is limited.
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7
Discussion
In this chapter, the main conclusions concerning the active control interface
capability of a VSC-HVDC wind-park are summarized and discussed.
Moreover, possible future work is suggested.
7.1
Conclusions
The control of both active and reactive power introduces more flexibility of a
VSC-HVDC wind park (WP) installation. However, there are some limitations
over the amount of the active and reactive power to be injected. From the
grid viewpoint, the main limitation is its impedance as seen from the point of
common coupling where the WP is installed. This impedance is generally
different for different voltage levels. It has been shown in this study that with
high grid impedance less full-regulation area of the voltage is feasible.
From the WP installation viewpoint, it has been demonstrated that the current
limitation of the front-end converter sets a limit to the reactive power that can
be injected. The higher the amount of injected active power is, the lower the
reactive-power limit. This reactive-power limit sets in turn a limit to the
voltage-control capabilities of the controller. A comparison has been made
between two current limitation algorithms: the first (referred to as L1) limits
only the injected reactive current while the second (referred to as L2) allows
for the active current to be decreased in order to increase the injected
reactive current without the violation of the limit. By using L2, the number of
trips of a nearby sensitive load can be significantly decreased compared to
using L1. In the study case considered here, an improvement by a factor of 2
(half the number of trips) has been found for equipment voltage sensitivity of
0.8 p.u. Applying L2 requires however extra investment in the system in order
to regulate the active power with a fast response. The controller can also be
used to improved the voltage-dip immunity (often referred to as “fault-ridethrough”) of the wind-power installation itself or of nearby wind-power
installations.
The simulations with reactive-power control only have been performed for X/R
ratios of 1 and 5. The simulations with combined active and reactive-power
control have been performed for X/R ratio equal to 10. The latter is
representative for the higher voltage levels at which wind parks will be
connected.
The basic voltage controller depends on controlling the reactive power
injected into the grid, which is carried out using the front-end converter. The
use of a DC current chopper has been introduced here in order to control the
active power. A comparison between using reactive power control and using
combined active and reactive power control has been carried out for different
phenomena in the grid. The comparison results are summarized in Table 7-1.
For combined active and reactive power control a distinction is made between
three types of controllers: the chopper control discussed in Chapter 5, battery
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storage control, and a controller that aims at changing (typically reducing) the
power production by the wind turbines themselves.
With the reactive power control, it is possible to regain the voltage amplitude
in case of a drop (e.g. due to switching of local loads or voltage dips) as long
as the current limit of the converter is not reached. For low wind-power
production the mitigation capabilities are less than for high wind-power
production. Also slow voltage variations can be compensated for. However,
harmonic distortion in the grid voltage cannot be attenuated in this way due
to the limited bandwidth of the controller. However, adding the active power
control capability results in better regulation for both the voltage at the PCC
and the DC voltage. Moreover, with the active power control more regulation
capability is achieved when the current limit is reached, since in that case the
active power could be temporarily lowered in order to allow for more reactive
power to be injected into the grid.
The contribution of the wind-power installation to operational security of the
grid takes place at longer time scales than the ones considered in this study.
Reduction or increase (where possible) of the wind-power production by the
turbines is the most appropriate for this. Obviously, as long as the current
limit is not reached, the reactive-power controller can contribute to
operational security by injecting reactive power on request from the network
operator.
Table 7-1 Comparison of reactive and active/reactive power control, shadowed blocks
are not considered adequate application.
Combined active and reactive power control
Response
time to
grid
dynamics
Only reactive
power control
Chopper control
Battery
storage control
WP control
Milliseconds
Milliseconds
Seconds
Seconds
Compensation
Switching
with limited
of local
Compensation energy depending
loads
on the chopper
design
Voltage
dips at
the grid
Compensation
of shallow
dips
Compensation of
higher dips
Grid
Compensation Compensation not
voltage
not significant
significant
harmonics
67
Compensation
with better
transients
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Better
Voltage
compensation for
amplitude Compensation
both AC and DC
variation
voltage
System
security
measures
Contribution
Contribution
Using a DC current chopper has been proposed here in order to achieve fast
control over the active power and has been proved to be effective in case of
the compensation for voltage amplitude variation and low voltage dips (less
than 0.6 p.u. in the case study here). Battery storage devices, in spite of
some environmental concerns, are the most economical technique. If their
cost is reduced and higher ratings are commercially available, SMES
(superconducting magnetic energy storage) would be the more effective
solution for active power control through storage. This is due to their very fast
time response, ability to compensate for oscillating power, unlimited
operational time, long lifetime, and almost no environmental impact.
7.2
Future work
With the vision of the future power grid in mind [45], envisaging the grid to
be more flexible, reliable, accessible, economic and environmentally friendly,
it seems quiet natural continuing the research and development on the active
interface possibilities of wind parks. Some of the ideas that mainly came out
of this work are briefly stated:
•
Study the speed limitations of the controller. There appear to be some
stability concerns when the controller speed becomes too high. This should
be further investigated as the speed limitation makes the controller less
suitable for mitigating flicker, voltage dips and harmonics.
•
The study of the propagation of different voltage quality phenomena to the
VSC-HVDC WP installation, and how they can impact each part of the
installation. This also could be interesting in the case of forming a DC grid.
The study of the impact of the AC grid on the DC grid could result in
raising requirement of the quality of the AC grid that the WP could connect
to.
•
The compensation of voltage harmonics has appeared to be a hard job for
the WP to compensate for. It could be interesting to put this phenomenon
in focus and develop the control system in order to compensate for it.
•
Apply the combined active-reactive-power control for fault-ride through
and other requirements set by the network operator.
•
Apply the control concepts to DFIG generators and to small installations
like microturbines. Moreover, studying the requirements for the plug-andplay concept for such installations.
68
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•
Dimensioning of the dc link capacitor and the chopper reactance. The size
of these will likely be determined by the requirements placed on the
performance of the installation.
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Appendix—System description and
per-unit calculations
In this appendix the system used in the simulations is described. Also the perunit base values are given. In Fig. A.1 an overview of the system used in the
simulations in PSCAD is shown. In the following subsections the different
parts are described.
Fig. A.1 Overview of the system used in PSCAD for simulations.
i)
Grid equivalent
The grid is modeled as an ideal 40 kV voltage source behind a transformer.
The transformer ratings are 25 MVA, 40/10 kV, Y/Δ and X = 10 %.
ii)
Feeder
The feeder that connects the WP to the grid is modeled as a resistance and
inductance in series. Different values are used for the individual simulations.
These values are given in the text.
iii)
Loads
The grid and local loads are modeled as PQ-loads for AC with values given in
the text. When simulating a harmonics-generating load a pure resistance is
used behind a three-phase full-bridge diode rectifier. The different values are
given in the text.
iv)
Wind-power installation (“Distributed generation”)
The wind-power installation can be further divided into three separate units:
the energy source, the VSC and the LCL-filter.
v)
Energy source
In the simulations of the converter with reactive-power control only the
energy source is modeled as an ideal DC voltage source with a voltage
U dc = 2
2
2
uac, rms = 2
10 = 16.33 kV .
3
3
74
(A-1)
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In the simulations of the converter with active and reactive-power control the
energy source is modeled as an ideal current source.
vi)
VSC
The VSC is built up with PSCAD standard components (IGBTs and diodes).
The construction is shown in Fig. A.2. The VSC rating is 10 kV and 2 MVA.
Fig. A.2. The voltage source converter used in PSCAD.
vii)
LCL-filter
In Fig. A.3 the LCL-filter used in the simulations is shown. The values are
calculated to fulfill the demands in [28].
Fig. A.3. LCL-filter used in the simulations in PSCAD.
The line-side inductance is modeled as 4.963 mH inductance in series with a
159.9 mΩ resistance. This inductance represents the leakage inductance of a
connection transformer. The converter-side inductance is modeled as a 13.05
mH inductance in series with a 410 mΩ resistance. Between the inductors is
placed a Y-connected capacitor bank modeled as a 5.512 μF capacitance.
viii)
Per-unit base values
The following values are used as base values for the per-unit calculations.
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U b = 10 kV
S b = 2 MVA
Ib =
Zb =
Sb
= 115 A
3U b
U b2
= 50 Ω
Sb
76