Download The utilization of synthetic inertia from wind farms and its

The utilization of synthetic
inertia from wind farms and its
impact on existing speed
governors and system
performance
(Part 2 Report of Vindforsk Project V-369)
Elforsk rapport 13:02
Mohammad Seyedi, Math Bollen, STRI
January 2013
ELFORSK
The utilization of synthetic
inertia from wind farms and its
impact on existing speed
governors and system
performance
(Part 2 Report of Vindforsk Project V-369)
Elforsk rapport 13:02
Mohammad Seyedi, Math Bollen, STRI
January 2013
ELFORSK
Preface
Sweden and other Nordic countries have ambitious renewable energy source
(RES) integration target. This will represent a significant share of wind power
in the future generation mix of Nordic countries.
From a power system point of view, total understanding of technical impacts
of this new generation source on the existing power system is vital to ensure
a secure and reliable operation of the power system. In a higher wind power
penetration scenario, wind power plants will need to contribute to system
voltage and frequency control support, which is quite obvious and logical.
In order to identify the possible impact of large scale wind power integration
and to recommend on possible approaches to manage the impact the project
described in this report was carried out with the research program Vindforsk
III as project V-369 “PosStaWind”.
The project consists of three parts focusing on different aspects of impact of
wind power on the angular, frequency and voltage stability of a power
system.
This report consist the report for part 2 of the project. A summary report for
all three parts of the project is available as in Elforsk report 13:04.
The project is financed by Vindforsk III with substantial initial funding from
the power system operators in Finland, Norway and Sweden, Fingrid, Statnett
and Swedish National Grid.
Vindforsk-III is funded by ABB, Arise windpower, AQ System, E.ON Elnät,
E.ON Vind Sverige, Energi Norge, Falkenberg Energi, Fortum, Fred. Olsen
Renewables, Gothia Vind, Göteborg Energi, HS Kraft, Jämtkraft, Karlstads
Energi, Luleå Energi, Mälarenergi, o2 Vindkompaniet, Rabbalshede Kraft,
Skellefteå Kraft, Statkraft, Sena Renewable, Svenska kraftnät, Tekniska
Verken i Linköping, Triventus, Wallenstam, Varberg Energi, Vattenfall
Vindkraft, Vestas Northern Europe, Öresundskraft and the Swedish Energy
Agency.
The work has been carried out by STRI with Nayeem Ullah and later with
Seon Gu Kim as a project leader. Several people at STRI have contributed to
the work.
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Comments on the work and the final report have been given by a reference
group with the following members:
Tuomas Rauhala,
Nikkilä Antti-Juhani
Terje Gjengedal,
Katherine Elkington,
Johan G. Persson,
Staffan Mared,
Kjell Gustafsson,
Fingrid
Fingrid
Statnett
Svenska Kraftnät (National Swedish Grid)
E.ON
Vattenfall
Statkraft
Stockholm January 2013
Anders Björck
Programme manager Vindforsk-III
Electricity and heat production, Elforsk AB
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Sammanfattning
Med ökande mängd av ansluten vindkraft i kraftsystemet, kommer mängden
av konventionellt anslutna enheter (i Sverige främst vatten- och kärnkraft) att
minska under perioder av hög vindkraftsproduktion. Genom att koppla bort
dessa konventionella enheter förlorar systemet också deras bidrag till
stabiliteten i systemet. Studien har analyserat vilken effekt vindkraftsproduktion har på frekvensstabiliteten i kraftsystemet, särskilt genom sitt
bidrag eller brist på bidrag till tröghetsmomentet i systemet.
Denna rapport visar att vindkraftsparker med DFIG-motorer (enligt GEmodellen i PSSE) eller med fulleffektomvandlare, inte bidrar till det totala
tröghetsmomentet i systemet. Resultatet av att ersätta konventionella
produktionsenheter med vindkraftsparker är med andra ord en reduktion av
kraftsystemets totala tröghetsmoment och detta försämrar därmed
möjligheten för systemet att upprätthålla nätfrekvensen.
Att installera vindkraftverk med syntetisk tröghet är ett sätt att förhindra
denna försämring. Ett antal studiefall har genomförts för att analysera hur
syntetisk tröghet påverkar frekvensen i systemet efter förlusten av en stor
produktionsenhet. Simuleringar har utförts i en modell av det nordiska
kraftsystemet (utökat Nordic-32).
Effekterna av den syntetiska trögheten som funktion av förlust av produktion
(i procent av den totala produktionen) sammanfattas i tabellen nedan.
Förlust av
produktion
4%
12%
16%
utan syntetisk tröghet
Lägsta
frekvens
49.30 Hz
48.45 Hz
48.25 Hz
tid att
återhämta
23 s
26 s
26 s
med syntetisk tröghet
Lägsta
frekvens
49.45 Hz
48.75 Hz
48.55 Hz
tid att
återhämta
38 s
42 s
43 s
Resultaten visar att vindkraftverk kan bidra till frekvensenstabilitet under de
första sekunderna efter en förlust av en stor produktionsenhet, genom att den
lagrade rörelseenergin omvandlas till syntetisk tröghet. Detta gör det möjligt
att höja den lägsta frekvensen och att förhindra lastbortkoppling (load
shedding?) på grund av underfrekvens. Detta bidrag av syntetisk tröghet från
en vindkraftspark är dock inte tillräcklig för att förhindra en större nedgång av
frekvensen vid ett större bortfall av produktion i systemet.
Simuleringarna visade också en del nackdelar med att använda syntetisk
tröghet: det fördröjer nätfrekvensens återhämtning och det ställer högre krav
på de primära reserverna.
De studier som utförts för att hitta optimal inställning för regulatorn visar att
de standardvärden som tillhandahålls av tillverkaren anses som de mest
optimala. Att försöka hitta den mest optimala regulatorinställningen innebär
att man kompromissa mellan att kunna få ett maximalt bidrag under de första
sekunderna efter en förlust av en produktionsenhet och behovet av ytterligare
kraft som då resulterar i en fördröjd återhämtning av nätfrekvensen.
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Summary
With increasing amounts of wind power connected to the power system, the
amount of conventional units connected will reduce during periods of high
wind-power production. By removing conventional units (in Sweden especially
hydro and nuclear) the system also loses their contribution to the stability of
the system. In this study we consider the impact of wind power on frequency
stability, especially through their contribution or lack of contribution to the
moment of inertia of the system.
It is shown in this report that wind farms with DFIG machines, according to
the GE model in PSSE, do not contribute to the total moment of inertia in the
system. Also it is known that turbines with full-power converter do not
contribute to the system inertia. As a result of this, replacing conventional
production units with wind farms results in a reduction of the total moment of
inertia and thus in a deterioration of the frequency quality.
Installing wind turbines with synthetic inertia is a way of preventing this
deterioration. A number of studies have been performed to study the way in
which synthetic inertia impacts the frequency excursion after the loss of a
large production unit. Simulations have been performed of an augmented
Nordic-32 model of the Nordic power system.
The impact of synthetic inertia, as a function of the loss of production (in
percent of the total production) is shown in the table below. Synthetic inertia
(WI) can support the frequency in the first few seconds after a loss of
production.
Loss of production
4%
12%
16%
Without synthetic inertia
Minimum
frequency
49.30 Hz
48.45 Hz
48.25 Hz
Time to
recover
23 s
26 s
26 s
With synthetic inertia
Minimum
frequency
49.45 Hz
48.75 Hz
48.55 Hz
Time to
recover
38 s
42 s
43 s
Accordingly, wind farms are able to contribute to the frequency stability
during the first few seconds after a loss of production by extracting the stored
kinetic energy through synthetic inertia. As a result, it is possible to increase
the minimum frequency and to prevent under-frequency load shedding.
However the contribution from the synthetic inertia might not be sufficient to
prevent a large frequency drop in a severe loss of production.
The simulations also showed some disadvantages of the use of synthetic
inertia: it delays the frequency recovery and it puts higher demand on the
primary reserves.
According to optimal tuning performance studies, the default parameter
values provided by the manufacturer are deemed as optimal parameters.
However the selection of optimal parameter might be a trade-off between the
contribution during the initial seconds after the production loss and the need
for additional power resulting in a delayed frequency recovery.
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Contents
1
Introduction
1.1
1.2
1.3
2
Frequency control in power systems and the impact of wind
power
2.1
2.2
2.3
Literature search
4
Modelling GE 3.6 MW DFIG wind turbine in PSS/E®
5
6
6.4
7
8
18
32
Presumptions ................................................................................. 32
Contribution of wind turbines to moment of inertia .............................. 32
Synthetic inertia ............................................................................. 34
6.3.1 Case 1 – 4% loss of production ............................................. 34
6.3.2 Case 1 – 12% loss of production ........................................... 35
6.3.3 Case 1 – 16% loss of production ........................................... 36
6.3.4 Comparison ........................................................................ 37
6.3.5 Speed and power production of the wind turbines .................... 37
6.3.6 Case 2 – Loss of three unit ................................................... 39
Optimal tuning of parameters in Wind Inertia module .......................... 41
Conclusion
7.1
7.2
10
Nordic-32 power system .................................................................. 18
Description of Case 1 ....................................................................... 26
Description of Case 2 ....................................................................... 30
Simulation results
6.1
6.2
6.3
8
Load flow model of wind turbine........................................................ 11
Dynamic model of GE 3.6 MW wind turbine ........................................ 12
Synthetic inertia ............................................................................. 16
Grid code with regards frequency ranges ........................................... 17
Test network
5.1
5.2
5.3
3
Basics of frequency control ................................................................. 3
Impact of wind power ........................................................................ 4
Synthetic inertia ............................................................................... 6
3
4.1
4.2
4.3
4.4
1
Background ...................................................................................... 1
Frequency regulation ......................................................................... 1
Outline of the report .......................................................................... 2
44
Findings ......................................................................................... 44
Future work.................................................................................... 45
References
Appendix A: GE 3.6 MW Wind Turbine Parameter Values
A.1
A.2
A.3
A.4
A.5
46
48
GEWTA –GE Wind Turbine Aerodynamics ...................................... 48
GEWTE1 – GE Wind Turbine Electrical Control ............................... 48
GEWTG1 - GE Wind Turbine Generator/Converter .......................... 50
GEWTP - GE Pitch Control ........................................................... 51
GEWTT - GE Two Mass Shaft ....................................................... 51
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1
Introduction
1.1
Background
Elforsk is administrating a four year wind energy research program “Vindforsk
III”. The program will be finished by the end of 2012. An evaluation will be
done as a part of the program [1].
The integration of large wind power plants into existing network and its
impacts on power systems stability issues is one of the main concerns for
Vindforsk III program and therefore with increasing the percentage of power
generation from wind farms the importance of analyzing some aspects such
as security and reliability of the power system cannot be ignored. The ability
of wind turbines to support power system for voltage and frequency stability
is one of the vital issues in some countries in such a way they have started to
establish some new grid codes with more demanding requirements on wind
power plants.
The aim of the study presented in this report is to find out the impact of wind
power integration on the system frequency stability. The study has focussed
on large unbalance between production and consumption, typically due to the
loss of a large production unit.
1.2
Frequency regulation
The frequency regulation and automatic generation control (AGC) are being
performed by conventional synchronous generators in almost all power
systems. Traditionally, wind parks have not contributed to system frequency
support. However, as the global penetration of wind power into the grid
increases, the grid code requirements are gradually becoming more
demanding. Apart from the most known so-called “fault-ride through”
capability for wind farms the frequency stability support is also becoming an
important issue. In other words, with increasing the size and capacity of wind
parks it is expected that wind power plants also be able to contribute to the
frequency stability. It means that wind parks, like other conventional
synchronous generators, should provide more active power following a
reduction in power generation or increasing load to limit the drop or rise in
frequency.
Wind turbines have considerable kinetic energy stored in their blades and
rotating mass and this energy can be extracted to support the primary
frequency regulation. However, in a variable speed wind turbine the rotor is
partly or completely connected to the network through a power electronic
converter and therefore there is no direct contact to the power system.
Hence, the power system frequency deviation cannot be sensed by wind
turbines and with wind turbines substituting conventional synchronous
generators the total inertia of the power system decreases and will aggravate
frequency stability. The kinetic energy available on the blades and rotor of a
wind turbine can be extracted like conventional synchronous generators
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inherently provided that some extra measures are considered. This report
deals with how it has been carried in a model presented by GE through the
so-called ‘synthetic inertia’ support. The report also provides the optimum
control parameters data for tuning the ‘synthetic inertia’ controller.
1.3
Outline of the report
After this introductory chapter, the report is organized as following:
•
Chapter 2 explains the relationship between active power and
control of frequency in a power system.
•
Chapter 3 presents an overview of some previous studies.
•
Chapter 4 illustrates, in brief, how the DFIG wind turbine is
modelled in PSS/E and the procedure for controlling active and
reactive power.
•
Chapter 5 describes how the test model network has been set up.
•
Chapter 6 shows the result of simulations for two different operating
conditions.
•
Chapter 7 presents the overall conclusions regarding this study
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2 Frequency control in power
systems and the impact of wind
power
2.1
Basics of frequency control
The frequency inside a power system should as much as possible remain
within a certain band. The limit for over and under frequency is clearly
specified for each country in the relevant grid code. Any mismatch between
produced and consumed power results in change in frequency. This change in
frequency activates the frequency control and governors. The frequency
control is such that the balance between production and consumption is kept
by maintaining the frequency close to its nominal value.
The frequency control takes care of the continuous and relatively small
unbalances between production and consumption due to the impossibility to
exactly predict consumption and production from certain units (mainly
renewable energy). The frequency control also intervenes when a large
unbalance occurs, for example due to the loss of a large production unit. This
is when the largest frequency drops occur; the design of the frequency control
(including the scheduling of the primary reserve) should be such that even for
the loss of the largest production unit, the frequency remains above a pre-set
limit. This lower limit is, for most large interconnected systems, such that
even for the loss of the largest production unit, no under-frequency load
shedding occurs.
To quantify the system behaviour upon loss of a large production unit,
consider the equation for conservation of energy for the rotating mass of all
machines connected to the power system:
=
−
(2.1)
Where J is the total moment of inertia of all rotating mass connected to the
power system, i.e. all electrical motors and all generators. Any unbalance
between production and consumption results in a change in the kinetic energy
of the rotating mass and thus in a change in frequency.
The relation between power unbalance and change in frequency is typically
written in the following form [8]:
= !
3
(2.2)
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Where
is the nominal power system frequency,
production,
is the total consumption and
rotating mass connected to the system.
is the total
"# the total kinetic energy of
Note that the inertia constant H includes all rotational mass that is directly
connected to the grid, including motors that are part of the consumption.
Inertia can be interpreted as “resistance to change” and it prevents the grid
frequency changing suddenly. It is because synchronous machines have large
and heavy rotating parts; and their high amount of kinetic energy is an
obstacle against fast change in frequency level.
The kinetic energy of a mass with moment of inertia J rotating at angular
speed ω is equal to
$%& = (2.3)
The kinetic energy of a power production plant is usually expressed through
“inertia constant”, # . The inertia constant, # , is the ratio of kinetic energy at
nominal rotation speed and the rated apparent power of the unit:
#=
where
(
)
' *+, )
-./
(2.4)
is the nominal rotation speed.
The process of frequency change can be divided into temporary or short-term
and permanent or long-term phenomena. The so-called automatic generation
control (AGC) of synchronous generators changes the input mechanical power
delivered to the shaft in response to a deviation in frequency from the set
point value. The deviation in frequency following a sudden change in active
balance for the first seconds is mainly affected by the inertia of power system.
This is because AGC is not able to have an instantaneous action.
2.2
Impact of wind power
Conventional power production units are connected to the grid by means of a
synchronous machine. The speed of the synchronous machine is directly
coupled to the frequency in the grid (hence the name “synchronous”). As a
result any change in frequency in the grid will result in a change in speed of
the generator. In terms of the above equations: the total kinetic energy of the
rotating mass in conventional power stations contributes to the system
inertia; SH in equation (2.2).
However, modern variable speed wind turbines (VSWT), use back to back
power electronic converters for magnetizing their exciters and so there is an
electrical decoupling between the rotational speed of the machine and the
frequency of the grid. A change in system frequency does not impact the
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machine. Although they have large amount of kinetic energy, such wind
turbines do not contribute to the system inertia. In a system with large
amounts of wind power, during periods of high wind, the conventional
synchronous generators are replaced with these types of wind turbines and as
result the total system inertia will be reduced.
Double-fed induction generators are partly connected to the grid through a
power-electronic converter and partly directly connected. Their contribution to
the system inertia is not immediately clear. We will see later, in Section 6.2,
that the contribution from a DFIG is small and can be neglected.
The ratio between the kinetic energy of the rotating mass and the rated
power of a generator, the so-called inertia constant, symbol H, is of the same
order of magnitude for conventional production units. This is illustrated in
Figure 2.1. With some exceptions, the inertia constant is between 2 and 6 s.
Figure 2.1 Inertia constant of hydro units (stars) and steam units (circles)
over a range of rated power, from different sources [8, Figure 8.25].
To quantify the impact of wind power on the system inertia, assume that all
conventional production units have the same inertia constant Hconv and that
the contribution from wind power to the system inertia is zero. We further
neglect the contribution from load to the system inertia. In terms of (2.2) this
translates as:
"# = #
0
×"
0
(2.5)
Where " 0 is the rated power of all the conventional production remaining
connected to the grid after the loss of the large production unit.
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Before the loss of the large production unit, the production is equal to the
consumption:
=
=
2&
+
0
+Δ
(2.6)
In the above equation, 2& is the contribution from wind power,
0 is the
contribution from conventional production units after the loss of the large
production unit, and Δ is the loss of production. The latter is also the
unbalance between production and consumption immediately after the loss of
the large production unit.
Combining (2.5) and (2.6) with (2.2) gives the following expression for the
initial rate-of-change-of-frequency (ROCOF) after the loss of a large
production unit.
=−
!
5
6
×
7
6
(2.7)
The first factor on the right-hand side is constant; the ROCOF is thus
proportional to the ratio between the amount of production being lost and the
total installed capacity of conventional generation.
The dimensioning event for frequency stability is the loss of the largest
production unit. The worst-case situation, fastest decrease in frequency,
occurs for the smallest amount of conventional production in operation. This is
when the consumption is small, there is high amount of production from wind
power, and export is small or import is large.
The good news is that this combination has a low probability of occurring.
Wind-power production is highest during the autumn and winter months,
whereas consumption is lowest during summer. High wind-power production
in combination with low consumption will also result in low electricity price,
which normally results in export.
However, situations with low amount of conventional production will occur
more often in a system with large amounts of wind power. Measures are
therefore needed to prevent too fast decrease in frequency upon the loss of a
large production unit. Several such measures have been discussed in the
literature (see e.g. [8] for an overview). One such measure, equipping wind
turbines with synthetic inertia, is introduced in the next section and the main
subject of the remainder of this report.
2.3
Synthetic inertia
The kinetic energy stored in rotational parts of wind turbines can be extracted
through a control strategy referred to as “synthetic inertia”. The control
system detects the frequency deviation and adjusts the power flow into the
grid based on this. In this way the turbine contributes to the system as if it
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would have inertia just like conventional units; hence the term “synthetic
inertia”.
The use of synthetic inertia is being discussed by several transmission-system
operators. For example, the grid code in Great Britain requires wind parks to
participate in frequency support and a study by the British TSO, National Grid,
regarding synthetic inertia has come to the conclusion that a power increase
of 5 to 10% during a grid frequency deviation of 0.8 Hz in approximately 8
seconds would be enough [20, 21, 22].
The use of synthetic inertia is also being discussed as part of the ENTSO-E
requirements for the connection of generators [4].
For any rotational mass, power equals to rotational speed multiplied by
torque:
= 8.
(2.8)
If the electrical torque is artificially increased the power will also be increased,
the turbine blades slow down and kinetic energy stored in the blades and
rotor is extracted. The additional torque, or power, is demanded by a
controller based on the measured frequency in the grid.
However, the normal controller of a wind turbine when detecting this
reduction in rotational speed will reduce the torque (and thus the power flow
into the grid) in order to recover rotational speed. This is exactly opposite of
what is needed.
Therefore, an artificial or synthetic extra power, depending on the frequency
deviation magnitude, is added to the set point power value. It should be only
active for certain frequency excursion values due to large active power loss
which is determined by dead-band setting. The maximum additional power
should be limited to a value of 5 to 10% in order to avoid unrealistic power
demands.
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3
Literature search
As was mentioned earlier large amounts of wind power are expected to be
part in the power system and therefore some countries have started establish
new grid codes relevant to wind farms. Among them is the requirement of
wind farms to participate in frequency control. The inherent characteristic of
converter-based variable-speed turbines in supporting system frequency for
short term or what is so called primary response has been taken into account
and has been a good motivation for some research works [8]-[10].
The relation between kinetic energy and transient stability of the power
system is also addressed in [8]. It is stated that a reduction in kinetic energy
which is in turn directly related to the total inertia constants of the power
generation plants will lead to weaker power system in terms of frequency
stability. The impact of distributed generators, where wind farms are also
sorts of distributed generators, has been discussed. It is mentioned that with
replacing large conventional generators connected to the transmission grid by
distributed generation same as wind parks will change the amount of kinetic
stored energy in the network and consequently can impact the frequency
stability of the power system. It is also stated for frequency stability studies
the contribution of the consumption side, loads, to the system inertia, which it
is not impacted by introducing distributed generators, should be taken into
account. The inertia constant of the power network will considerably decrease
with introducing distributed generators equipped with power electronic
interfaces. However, it is pointed out by building a so-called electronic inertia
like using rate of change of frequency (ROCOF) it is possible to extract the
stored kinetic energy from the rotating masses.
In [9] first the different stages in frequency decline resulting from the power
imbalance are illustrated. In the first phase, the very first instance after
disconnecting a big unit from the grid, generators deliver a certain amount of
additional power to the grid depending on their shift angles. The second phase
is the inertia action stage when the additional power is delivered to the grid
from the stored kinetic energy of rotating parts. This phase is characterized
by a decline in speed. The third phase which is called governor stage is the
period when turbine governors detect the decline in speed. The difference
between the set point and the measured value for network frequency acts as
an input for the governor. The reaction by governor is to increase the
mechanical power on the shaft of turbine generator and therefore more
electrical power will be injected to the network. This process will end up with
a steady state deviation in frequency due to droop characteristics of the
frequency control. The importance is emphasized of establishing real grid
code requirement and pointing out the lack of concrete demands. It also tries
to compare the different control strategies to perform frequency supporting
from wind turbine through extracting more active power from wind turbines.
It is concluded that the most suitable pattern is soft-fast frequency response
(SFFR) from technically and robustness point of views. The SFFR is a ∆f type
controller with a time delay. The advantages of this are according to the
study, the simplicity of the model and consequently the lower cost.
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The increasing penetration of converter interfaced generation into the power
system and consequent impact of power system inertia is also indicated in
[10]. By replacing conventional synchronous generators with converter units
where their rotor is not directly connected to the grid the total inertia
available to the power system is decreased, which makes the power system
more vulnerable against frequency excursions. In [10] a comparison is made
of the different controlling methods to exploit the kinetic energy of wind
turbines. It is concluded that a method called fast power reserve (FPR) is able
to extract the extra power from the rotor up to 10% of actual power. The
controller will be activated once the decline in the frequency goes below a
threshold value a pre-specified trapeze power reference will be generated and
applied to all WTs. Among the advantages which are claimed by deploying the
proposed control system is that the operator has information about how much
extra power wind turbine can provide in case of losing generation in the
system. It also stated that the response from the system is fast and the
amount of extracted extra power from the WT during under frequency period
is controllable in order to limit the impact on the recovery period. It is shown
that with higher FPR step, (∆P), the frequency recovery time period will be
longer. However, the additional power is limited to maximum 10% of preevent active power.
Another study was performed in Germany [11] regarding the ability of wind
farms in providing frequency control. The study tried to point at the two main
concepts. Firstly, a procedure to calculate/estimate the amount of frequency
control is illustrated and then it is tried to develop a measure to handle the
effect of introducing wind farms on decreasing the power system inertia
through applying control strategies on wind turbines. In the study the
necessity of frequency support by wind farms is indicated by comparing the
future planned power production with real power production. For the first part
a probabilistic method is presented to forecast the amount of power which can
be exploited when it is needed to support the frequency.
In [11] an economic analysis for different wind farms is also presented and it
is shown that the profit depends upon the level of security and price per kW.
In the study it is concluded that the best option with the highest profit is
through combining the wind farms in a virtual power plant.
From the former studies it can be realized the simplest and most economical
method for the purpose of participating wind farms in the primary frequency
support is to deploy the kinetic stored energy in their turbine rotating parts.
In this study an approach to use the stored energy in the rotating masses is
presented. The method is compliant with the GE report ver. 4.3 [15] and the
DFIG control strategy which is built in PSS/E® ver.32. Since the deviation in
grid frequency is applied to trigger the relevant module the algorithm in the
model is to some extend the same as SFFR which is the option offered by [9].
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4 Modelling GE 3.6 MW DFIG
wind turbine in PSS/E®
It is assumed all the wind turbines in the network are from the doubly fed
induction generator (DFIG) type. A simple layout of this type of wind turbine
is shown in Figure 4.1.
Figure 4.1 Doubly Fed Induction Generator
A DFIG is an induction machine in which the AC excitation system is equipped
with solid-state voltage source converter. The AC excitation system is
energized by the network through a back to back ac-dc-ac converter and it is
connected to the rotor winding through slip rings on the rotor shaft. The grid
side converter is supplied from tertiary winding of the step-up unit
transformer or through a separate two windings step-down transformer. The
dynamic behaviour of DFIG is quite different from either conventional
synchronous or induction machines. The dynamic performance of a DFIG at
the fundamental frequency is completely dominated by the converter.
Therefore, unlike conventional synchronous generators, some aspects of
generator performance related to internal angle, excitation voltage and
synchronism are not relevant. A voltage source inverter can be synthesized as
an internal voltage behind a transformer reactance which results in the
desired active and reactive current being delivered to the device terminal.
In a DFIG the combination of generator and converter establishes a currentregulated Voltage-Source Converter (VSC) where the stator and rotor
windings are the primary and secondary of the transformer. However, the ac
frequency in rotor winding is not the same as in the stator. In the vicinity of
rated power both GE 1.5 and 3.6 MW machines will normally operate at 120%
speed, in other word at -20% slip. Through controlling the excitation
frequency in a DFIG it is possible to control the rotor speed in a range of
approximately ±30%. Besides, by changing the rotor currents magnitude the
active power output can be controlled. Accordingly, A DFIG, same as a
10
ELFORSK
synchronous generator, has the capability of voltage regulation but with a
faster response.
4.1
Load flow model of wind turbine
The wind turbine type for all the wind farms in this study is GE 3.6 MW. In
each wind park a number of identical wind turbines are clustered and
connected to a common point. The result is a single equivalent large machine
behind a single equivalent reactance. The equivalent generator has the rated
output power equal to the number of wind turbines in the wind farm
multiplied by rated power of one DFIG, 3.6 MW,. The rated voltage at the
terminal of the DFIG is 3.3 kV which is increased through a step-up
transformer to 33 kV. The rated power of the step-up transformer is the
summation of the total number of individual wind turbine transformers. The
rated values data for a typical GE 3.6 MW wind turbine is presented in Table
4.1 [16]. The result of load flow calculation for two wind farms, each with 46
wind turbine units aggregated in one single unit is depicted in Figure 4.2.
Table 4.1 Induction Generator and unit Tr. Data for GE 3.6 MW Wind Turbine
Doubly Fed Induction Generator Rating
4.0 MVA
Pmax
3.6 MW
Pmin
0.16 MW
Qmax
2.08 MVar
Qmin
-1.55 MVar
Rated voltage, 50Hz
3.3 kV
XSOURCE
0.8 p.u
Unit Transformer Rating
4.0 MVA
Unit Transformer Impedance
7.0%
Unit Transformer X/R ratio
7.5
Unit Tr. Ratio
3.3/33 kV
11
ELFORSK
Figure 4.2 Load flow result for wind farm at buses 9113 and 9052
4.2
Dynamic model of GE 3.6 MW wind turbine
The dynamic model of GE 3.6 MW wind turbine is explained in detail in [16].
The blocks in Figure 4.3 represent the dynamic model connectivity for GE
wind turbines [15], [16].
The three main blocks are:
1.
Generator/converter model
2.
Electrical control model
3.
Turbine and turbine control model
The generator/converter model is the equivalent of the generator and field
converter, and provides the interface between the wind turbine generator and
the network. The model injects real and reactive current into the network in
response to control commands.
The controller provides the real and reactive power command for
generator/converter model. It includes both closed and open loop controls.
The dictated active and reactive powers are based on inputs from the turbine
model and from the supervisory VAr controller.
The basic objective of the turbine control is to maximize the extracted active
power from the wind while maintaining the rotor speed at the desired value
without overloading equipment. This model provides a simplified
representation of this complex electro-mechanical system.
12
ELFORSK
Figure 4.3 The GE DFIG Block diagram control Model Block Diagram
The turbine model represents the relevant controls and mechanical dynamics
of the wind turbine. The block diagram of the model is shown in Figure 4.4.
In the block diagram the following sub-modules can be recognized:
1.
The turbine control model including torque control, pitch control and
pitch compensation models
2.
Rotor mechanical model
3.
The wind power model
4.
Active power control emulator (APC)
5.
WindINERTIA model
Among the sub control models the two controller blocks of APC and
WindINERTIA are optional and can be either activated or disabled through
setting certain flag/parameters to zero or a non-zero value. The central part
of the WT model including pitch control and pitch compensation modules is
the model of the turbine controls. When the wind speed is lower than rated,
the pitch control module adjusts the blade angle in order to maximize the
extracted mechanical power. When the wind speed is higher than rated value,
and for the purpose of protecting equipment, the blades are pitched to limit
the mechanical power delivered to the shaft.
13
ELFORSK
Figure 4.4 GE Wind Turbine model block diagram
The Active Power Control (APC) is optional however with increasing the
penetration of wind farms to the network it become required by some grid
codes. The model of the APC is shown in Figure 4.5. The main objectives of
the APC are to:
•
Apply a maximum wind plant output
•
Provide a specific margin by generating less power than is available
from wind
•
Enforce a plant power ramp rate limit
•
Respond to abnormal system frequency excursions
14
ELFORSK
By default, the APC is disabled. When the APC is activated, the actual power
provided by a wind power plant is less than the maximum available power
from wind and there is a margin. This margin is in the range of 5% so the
actual power generated is 95% of the available power. When there is a
frequency drop and by activating the APC module more power will be
requested.
Figure 4.5 Active Power Control Module
The WindINERTIA (WI) module is an optional block in GE wind turbine which
is dedicated for transient frequency stability support. Figure 4.6 represents
the control diagram of GE WI.
Figure 4.6 The Wind Inertia control model in GE Wind Turbine
In the model dbwi is a block to specify the threshold or dead band value and
determine for how much deviation in frequency the controller should start to
respond. Tlpwi is the time constant for filter, Kwi is the gain value and Twowi is
the time constant for wash-out filter component.
A washout filter (also sometimes called a washout circuit) is a high pass filter
that washes out (rejects) steady state inputs, while passing transient inputs.
The main benefit of using washout filters is that all the equilibrium points of
15
ELFORSK
the open-loop system are preserved (i.e., their location isn’t changed). In
addition, washout filters facilitate automatic following of a targeted operating
point, which results in vanishing control energy once stabilization is achieved
and steady state is reached.
The output from WI module, ∆Pwi, is the additional active power which is
extracted from turbine following a decline in the frequency. The dynamic
characteristic of the network has impact on the following issues when there is
a decline in frequency resulting from power generation loss:
a) The rate of frequency decline ( )
b) The depth of frequency decline(< )
c) The time for frequency recovery (8=>?)
In this study the behaviour of wind parks for contributing in transient
frequency stability when the timescale is in the range of few seconds is
investigated. Therefore, module in GE wind turbine controller is assumed to
be disabled.
In the first few seconds following a large generation connected loss the inertia
of rotating mass of the turbines, generators motors has significant impact on
the frequency rather than slower active power governors where their longer
timescale. The conventional synchronous generators can provide inertia
inherently, but wind turbines which are decoupled from power system do not
provide it inherently. Instead, their large kinetic energy stored in the rotating
rotor and blades can be extracted and delivered to the grid by adding a
control module called synthetic inertia.
4.3
Synthetic inertia
The conventional control system of a variable speed wind turbine does not
consider the power system frequency. The frequency is used to synchronize
the switching of the power electronics of the network side converter but the
main control loop measures the rotational speed of the generator and applies
a torque so that the wind turbine follows its-predetermined operating
characteristic. Thus, in the event of a drop in power system frequency,
caused, for example, by the sudden disconnection of a large central
generator, a variable speed wind turbine will not provide any additional
energy as the system frequency falls. This is in contrast to a conventional
synchronous generator, or a fixed speed induction generator, that will transfer
some of its kinetic energy to the power system as the frequency and the
speed of rotation of the generator falls.
This lack of response of variable speed wind turbines to a drop in system
frequency can be overcome by adding additional control loops as shown in
Figure 4.6. The inertia is synthesized by measuring the rate of change of
system frequency. The magnitude of the frequency drop may be used to apply
additional torque to the rotor, slow it down and so transfer kinetic energy to
the network.
16
ELFORSK
4.4
Grid code with regards frequency ranges
The grid code requirements are different among different countries. In Table
4.2 the demands for frequency deviation in Sweden is compared with
Denmark and ENTSO-E grid codes.
Table 4.2 Grid code comparison
Parameter/Grid
Swedish Grid Code
Code
(SvK)
Continuous operating
frequency between
49 Hz to 51 Hz
continuous operating
voltage
Minimum frequency
between continuous
47.5 Hz
operating voltage
ROCOF limit
Not mentioned
Danish (Energinet.dk)
ENSTO-E
(draft 24 Jan. 2012
49.9 HZ to 50.2 Hz
49 Hz to 51 Hz
(for Nordic)
47.5 Hz
47.5 Hz (Nordic)
±2.5 Hz/sec for unit's
output range between
11kW to 25kW
Up to 2 Hz/sec
The regulation and general advice for the manual and automatic load
shedding in case of a frequency decline for Swedish power system is specified
by the Swedish power network (SvK) and it was finalized in December, 11th,
2001. The SvK prescribes the regulation (1994:1806) for the power
generating plants with an electric power at least 5 MW. The automatic load
shedding requirement is as follows [19]:
The power network that is directly connected to the transmission lines located
south of 61° latitude must be equipped with automatic load shedding (AFK).
Equipment for AFK should be installed in such a degree that disconnection can
be done at least 30 percent of the total current transmission each time
excluding electricity to the electrical installations. The automatic reconnecting
should be avoided.
The reconnection must be done only after receiving approval from Svenska
Kraftnät. The equipment shall be designed such that disconnection takes place
into five equal steps when the frequency is less than the following values:
-
Step
Step
Step
Step
Step
1:
2:
3:
4:
5:
48.8
48.6
48.4
48.2
48.0
Hz
Hz
Hz
Hz
Hz
in 0.15 seconds
in 0.15 seconds
in 0.15 seconds
for 0.15 seconds, and at 48.6 Hz in 15 seconds
for 0.15 seconds, and at 48.4 Hz in 20 seconds
17
ELFORSK
5 Test network
The objective of this chapter is to set-up test network and to prepare it for
performing simulations.
5.1
Nordic-32 power system
An augmented Nordic-32 test system is used for system study as it is
mentioned in the specification [1]. The original Nordic-32 consists of 32 main
buses and 9 loads. In the systems there are voltage levels which are 400 kV,
220 kV and 130 kV. Each bus has a 4 digit bus number where the first digit
specifies the different bus voltage levels which they are 4, 2 and 1,
respectively. The two digits bus numbers are also 130 kV level. There are
both thermal power plants and hydro units in the original Nordic-32 system.
The diagram of the original system is shown in Figure 5.1 and Table 5.1
presents the rated active and reactive power values for all the generating
plants including synchronous generators, synchronous condensers and wind
power parks in the augmented Nordic-32 power network.
A PSSE SLD diagram of the resulting augmented grid is shown in Figure 5.2.
Table 5.2 shows the rated active and reactive values for the loads in the
agumented Nordic-32 network.
18
ELFORSK
Figure 5.1The original Nordic-32 network
19
ELFORSK
1012
1013
1014
1021
1022
2032
4011
4012
4021
4031
4041
5100
5300
5400
5500
5600
6000
6100
7100
7101
4042
4047
4047
4051
4051
4062
4062
4063
1042
1043
7201
7203
7204
7205
8002
8500
3012
3022
3032
BUS1012
BUS1013
BUS1014
BUS1021
BUS1022
BUS2032
BUS4011
BUS4012
BUS4021
BUS4031
BUS4041
130.00
130.00
130.00
130.00
130.00
220.00
400.00
400.00
400.00
400.00
400.00
300
300
300
300
300
300
300
BUS4071 400.00
400
BUS4042 400.00
BUS4047 400.00
BUS4047 400.00
BUS4051 400.00
BUS4051 400.00
BUS4062 400.00
BUS4062 400.00
BUS4063 400.00
BUS1042 130.00
BUS1043 130.00
400
400
400
400
LIT2
400.00
400
FW_2
3.3000
FW_2
3.3000
FW_2
3.3000
Id
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
1
2
1
2
1
1
1
1
1
1
1
1
1
1
1
1
PGen QGen QMax QMin Mbase
(MW) (Mvar) (Mvar) (Mvar) (MVA)
264
125
400
-80
800
198
38
300
-50
600
363
100
350
-100
700
424
103
300
-60
600
132
35
125
-25
250
495
117
425
-80
850
473
132
500
-100
1000
530
25
400
-160
800
165
-30
150
-30
300
325
-40
175
-40
350
0
228
300
-200
300
423
173
9999 -9999
600
651
-9
9999 -9999
916
454
0
9999 -9999
633
237
37
9999 -9999
333
680
219
9999 -9999
950
383
-11
9999 -9999
466
671
343
9999 -9999
966
225
50
9999 -9999
333
140
125
9999 -9999
333
660
48
350
0
700
566
127
300
0
600
566
127
300
0
600
629
100
350
0
700
419
67
350
0
700
555
0
300
0
600
555
0
300
0
600
100
30
30
0
150
377
70
200
-40
400
189
100
100
-20
200
324
24
9999 -9999
433
689
62
9999 -9999
866
368
163
9999 -9999
475
368
48
9999 -9999
475
0
0
9999 -9999
500
333
391
9999 -9999
666
160
27
9999 -9999
184
160
8
9999 -9999
184
160
10
9999 -9999
184
20
Thermal units
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
Bus Name
Wind
Farms
No. Bus
Hydro units
Table 5.1 Power generating plants, in the Nordic-32 network
ELFORSK
10
40 3042 FW_2
3.3000
1 160
41 3052 FW_2
160
10
3.3000
1
42 7003 FW_3
81
3.3000
1 320
43 7013 FW_3
79
3.3000
1 320
44 7023 FW_3
81
3.3000
1 320
45 9012 FW_2
160
11
3.3000
1
46 9022 FW_2
6
3.3000
1 160
47 9032 FW_2
9
3.3000
1 160
48 9042 FW_2
10
3.3000
1 160
49 9052 FW_2
8
3.3000
1 160
50 9062 FW_2
-4
3.3000
1 160
51 9073 FW_3
27
3.3000
1 160
52 9083 FW_3
160
35
3.3000
1
53 9093 FW_3
56
3.3000
1 160
54 9103 FW_3
49
3.3000
1 160
55 9113 FW_3
37
3.3000
1 160
56 9123 FW_3
50
3.3000
1 160
Total Generation Capacity by Hydro power units
Total Generation Capacity by Thermal power units
Total generation Capacity by Wind Farms
Total Generation Capacity by all units
21
9999
9999
9999
9999
9999
9999
9999
9999
9999
9999
9999
9999
9999
9999
9999
9999
9999
-9999
184
-9999
184
-9999
368
-9999
368
-9999
368
-9999
184
-9999
184
-9999
184
-9999
184
-9999
184
-9999
184
-9999
184
-9999
184
-9999
184
-9999
184
-9999
184
-9999
184
7232 MW
6698 MW
3680 MW
17611 MW
333. 0
1
4063
4063
8500
8500
1
22
127. 6
- 49. 2
1
125. 3
- 53. 3
1
1. 0000
1. 0000
62
62
1. 0000
408. 0
- 52. 1
400. 0
- 45. 7
1
1
51
61
2
1. 0000
61
4061
1. 0000
4045
1. 0000
149. 8
15. 9
5
401. 2
- 54. 8
1045
4051
1. 9
20. 0
1
565. 9
126. 7
- 53. 1
130. 0
- 51. 0
129. 6R
565. 9
408. 0
- 44. 3
1. 0000
1044
1
1
1. 0000
133. 5
4047
75. 7
568. 9
1
50. 0
16. 8
565. 6
4046
200. 0
0. 0
98. 9
0. 0
4046
133. 9
1. 0000
1044
700. 0
249. 6
400. 0
125. 7
462. 8
126. 3
- 53. 2
1. 0000
193. 7
1
4051
0. 0
Nor dBalt
0. 0
0. 0
8001
8001
0. 0
1 1. 0000
400. 0
- 43. 0
7204
7204
1
4032
Fenno- Skan
127. 7
- 46. 8
1
1
1
9. 2
7205
7205
1
4021
4021
1
1
1
404. 0
15. 4
1
1
23. 8
24. 3
71. 6
71. 6
24. 3
74. 9
32. 6
24. 7 408. 2
10. 1
68. 4
1
68. 7
300. 0
70. 0
404.33.
0 0
12. 3
38. 9
5
75. 2
407. 5
28. 2R
92. 2
9. 4
4011
22. 9
4. 3
222. 1
36. 1R
7. 2
1. 0000
9. 4
1
91. 3
17. 4
402.13.
0 1
0. 0
92. 2
341. 0
2. 0
17. 4
3. 3
2. 4
18. 5
70. 5
70. 5
18. 5
4. 6
4. 6
50. 0
1
38. 8
93. 2
25. 4
20. 4
174. 7
20. 4
174. 7
7. 7R
222. 1
341. 0
50. 0
20. 5
113. 4
113. 4
20. 5
1
1. 4
359. 7
19. 7R
7102
154. 2R
70. 0
300. 0
108. 7
8. 2
7102
41. 2R
7203
7203
300. 0
7201
70. 0
7201
109. 3
13. 6
1
407. 5
0. 0
404.8.09
1. 4
15. 2
23. 0
154. 8
7101
764. 2
1
140. 0
138. 7
- 9. 3
200. 0
7101
153. 6
1
15. 6
262. 0
30. 0L
712. 7
36. 8
232. 4
654. 2
39. 6R
85. 0
576. 4
81. 9R
404. 0
0. 7
600. 0
571. 7
118. 5
67. 0
372. 6
30. 0
312. 7
504. 0
44. 6
1
2. 0
171. 5
2. 0
171. 5
150. 8
10. 2
1
65.5
12.4
700. 0
193. 7
65. 6
129. 6R
100. 0
400. 0
- 43. 8
100. 0
397. 6
- 49. 4
458. 5
93.2
45. 2
125. 7
400. 0
407. 7
- 32. 7
100. 0
45. 2
97. 7R
149. 4
1
80. 0
2
1. 0000
43
400. 0
5300
1. 90
300.
398. 1
- 51.10
0. 0
42
6. 2
1. 0000
43
197. 6
42
70. 0R
1. 0000
540. 3
0. 8
660. 2
463. 9
16. 2
1. 0500
377. 3
1
1. 0000
1. 0000
302. 7
4043
238. 8
618. 7
29. 8
231. 4
- 25. 1
238. 8
4043
637. 2645. 6
51. 7 38. 8
128. 6
1. 0700
1
126. 2
- 68.
146.
3 1
261. 3
900. 0
260. 6
20. 0
399. 4
- 47. 9
51. 2
4042
900. 0
4042
900. 0
1
0. 0
196. 4
5. 1
37. 2
128. 8
- 54. 2
180. 2
560. 4
60. 1
313. 7
17. 5
5. 1
462. 2
419. 2
90. 8R
112. 8
16. 9
16. 9
112. 8
314. 4
54. 8R
24. 3
24. 3
40. 0
219. 9
100. 0
216. 2
0. 1
216. 2
0. 1
232. 4
80. 1
200. 0
80. 0
1011
250. 0
1
560. 4
28. 0
146. 7
0. 0
199. 0
1
20. 9
800.
0
300. 0
19. 9
2. 9
19. 9
2. 9
5103
67. 1
408. 6
- 24. 4
1. 0000
43. 6
36. 5
4. 4
682. 4
155. 5
399. 5
- 11. 5
486. 7
22. 1
649. 5
462. 2
21. 9
1011
700. 0
481. 5
1. 0000
1045
1. 0000
481. 5
5
560. 4
60. 1
242. 0
- 12. 2
560. 4
28. 0
367. 3
4. 8
1. 0000
20. 9
180. 2
765. 1
645. 7
50. 9
184. 3
493. 9
24. 8
524. 0
0. 0
102. 0
110. 4R
148. 8
7. 91. 00
00
149. 8
15. 9
300. 0
- 50. 4
481. 5
67. 1
621. 3
611. 1
10. 8
1
28. 6
4032
46. 6
632. 9
61. 3
1012
481. 5
43. 6
4. 9
6
78.
404. 0
- 28. 3
325. 4
89. 7
53. 7
53. 7
726. 8
726. 8
326. 7
21. 4
1. 1200
89. 7
22. 0
325. 4
326. 7
8. 5
56. 9
0. 0
1
0. 0
2
323. 2
51. 9
144. 5
95. 0
280. 0
9.
21
0. 0
130. 0
- 62. 7
78. 4
4045
51. 9
357. 6
12. 4
323.
74. 9
361. 5
87. 7
4041 4044
4044
123. 3
4041
123. 3
87. 7
155. 0
101. 72
771.
144. 5
705. 6
198. 5
47. 7
198. 5
47. 7
209.
6
125. 0H
4011
28. 7
124. 0
4061
100. 0
124. 0
28. 7
1041
1012
300. 0
84. 6R
800. 0
302. 4
1043
191. 5
1043
705. 6
4031
46. 1
5100
101. 7
716. 6
324. 9
13. 1R
4031
0. 0
468. 4
82. 6
1. 0000
716. 6
1
628. 8
1041
468. 4
56. 0
30. 0
100. 0
1
200. 0
230. 0
13. 0
13. 0
284. 2
284. 2
4022
46. 1
686. 4
60. 9
686. 4
60. 9
1
45. 7
4012
176. 9
4022
28. 9
4012
0. 0
104. 0
419. 2
100. 0
156. 2
1
153. 7
1
14. 9
0. 0
36. 6R
143. 0
11. 3
100. 0H
146. 9
3. 5
9. 1
401. 1
- 49. 5
40. 8
0. 0
200. 0
130kV
0. 0
150. 0
15. 9
145. 1
15. 9
1014
9. 1
1. 0000
181. 1
1014
146. 3
1. 0000
188. 6
209. 6
22. 4
209. 6
22. 4
1022
600. 0
200. 0
.2
26
1
540. 0
156. 2
28. 9
2031
153. 7
14. 9
419. 2
44. 7R
1013
56. 4R
0. 0
293. 0
51. 1
2031
188. 5
293. 0
51. 1
1
800. 0
253. 2
1. 0000
135. 0
195. 8
200. 0
50. 0
1013
800. 0
253. 2
5603
80. 0
2
200. 0
61
400. 0
- 44. 7
0. 0
4062
145. 1
41
41
590. 0
4062
1. 0000
1. 0000
785. 9
152. 3R
220kV
301. 9
1
1
256. 2
590. 0
192. 6
220kV
1022
590. 0
256. 2
392. 6
- 49. 4
500. 0
.1
149. 0
60
179. 1
71. 8
1. 0000
8
5501
6.
11
.4
5. 7
46
4. 1
100. 0
5501
5101
320. 9
77. 3
11
7.
300. 0
400. 8
- 50. 8
5101
112. 3
38. 0
500. 0
0.3 0
409.
112. 3
500. 0
1. 0000
1
80. 0
300. 0
1. 0000
5100
30. 0H
5602
300. 0
- 51. 1
6.5
323. 1
40. 2
61. 4R
.2
26
160. 0
100. 0
1
126. 3
11. 8
281. 2
00
00
234. 6R
1.
12. 6R
5602
300. 0
9 - 48. 7
5500
5500
555. 4
5.7
23.9
17.
5400
128. 3
128. 1
- 47. 8
12. 6R
6. 2
.3
111
5400
540. 0
555. 4
49. 6
0
1. 000
540. 0
128. 3
9. 9
.2
111
13.3
89. 9
5. 6
0
1. 000
146. 0
129. 4
34. 6
1
146. 0
9. 9
300. 0
87.8
144. 2
16. 1
1.
00
204. 0
502. 3
326. 0
00
1319. 0
23.
2
399. 9
17.4 - 48. 7
25. 2
1014. 0
171. 2
6100
144. 2
23. 4
145. 2
90. 9
278. 0
- 62. 1
5102
16. 1
2032
90. 9
5503
356. 1
5102
27. 9
6100
1
12. 4
171. 3
2032
145. 2
400. 1
- 48. 9
31. 0
0. 0
539. 0
10. 2R
126. 6
6. 4
1
130. 5
1
9.9
1
5402
5402
7
5103
0. 4
11
2.
91 0
.3
359. 0
5
16. 1
300. 0
7. 6 - 53. 2
13
5.
24.60
400.
- 42. 0
41.6
5301
111. 153.
4. 4
90. 2
373. 1
- 60. 8
89. 9
5. 9
1. 0000
197. 3
8. 1
5600
5401
1. 0000
1. 0000
1. 0000
147. 8
5301
42. 2
89. 9
5.9
111. 1
5401
73. 2
1
1
5300
0. 0
1. 0000
223. 7
1
397. 3
- 51. 0
221. 0
1
1
1021
333. 0
333. 0
1. 0000
58. 2
6001
58. 2
11. 5
213. 4
1021
324. 9R
11
3.
4
10
0.
6
221. 0
49. 5
52. 7
399. 9
- 57. 5
220. 9
3. 7
133.
2
27
.0
5601
211. 5
5601
18. 1
796. 8
171. 0
18. 1
211. 5
6.0
23.2
89.83
15.
399. 8
1 1
-0.50.
466. 0
1. 0000
211. 5
19. 1
60003
88.
0
1. 000
99. 0
.0
806. 9
36
234. 6R
349. 7R
37. 1
5
6
2. 6
11.
33
.2
16
6001
207. 3
506. 8
146.
1
9. 4
8
2.
6.0
11. 2
300. 0
- 36. 7
0
1. 000
5600
508. 0
8
136. 9
67. 0
33
300. 0
- 49. 5
6.
10
1
3. 0
9
6.
10 . 9
32
300. 0
- 57. 8
1. 0000
135. 0
8. 0R
7
6000
8.6
207. 4
7. 9
1. 0000
15. 9
772. 3
146.
5.1
383. 1
8. 2R
1040. 0
ELFORSK
1
9
145. 4
1. 1
1.
12
00
400kV
400kV
1
404. 0
0. 6
7100
7100
1
1
407. 6
6. 4
7200
7200
404. 0
12. 1
1. 0000
5
397. 7
- 49. 0
1. 0000
404. 0
11. 0
46
700. 0
46
130. 2
- 46. 5
47
47
130kV
176. 9
1
1
129. 7
- 57. 5
1
1042
1042
1
1
1
1
Sout h- West
8002
8002
1. 0000 1
130. 1
- 55. 2
1
400. 0
- 43. 0
5
1. 0000
1
392. 0
- 48. 1
123. 6
- 51. 8
63
63
1
408. 0
- 48. 7
Figure 5.2 Modified Nordic-32 grid including the augmented Norwegian and
Finnish part.
ELFORSK
Table 5.2 rated active and reactive powers of loads
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
Bus
41
42
43
46
47
51
61
62
63
1011
1012
1013
1022
1041
1042
1043
1044
1045
2031
2032
4045
4046
4051
4063
5100
5300
5400
5500
5600
5603
6100
7100
7101
7201
7203
7203
7204
7205
8001
Bus Name
BUS41
130.00
BUS42
130.00
BUS43
130.00
BUS46
130.00
BUS47
130.00
BUS51
130.00
BUS61
130.00
BUS62
130.00
BUS63
130.00
BUS1011 130.00
BUS1012 130.00
BUS1013 130.00
BUS1022 130.00
BUS1041 130.00
BUS1042 130.00
BUS1043 130.00
BUS1044 130.00
BUS1045 130.00
BUS2031 220.00
BUS2032 220.00
BUS4045 400.00
BUS4046 400.00
BUS4051 400.00
BUS4063 400.00
300
300
300
300
300
300
300
BUS4071 400.00
400
400
400
400
400
400
LIT
400.00
Pload (MW)
551
408
918
714
102
816
510
306
602
204
306
102
286
612
306
235
816
714
102
204
200
-300
250
-200
1160
59
27
360
915
410
892
348
348
306
306
300
612
306
0
23
Qload (Mvar)
128
126
239
194
45
253
112
80
256
80
100
40
95
200
80
100
300
250
30
50
0
0
0
0
204
3
0
38
99
171
326
50
50
70
70
0
140
70
0
ELFORSK
40 8500
41 8500
Total
400
400
340
204
15658
333
0
4382
The following dynamic models for thermal and hydro generators, exciters and
stabilizers are used [13].
•
GENSAL
It represents a salient pole generator and is used for all hydro power
generating units. The block diagram of the generator is shown in
Figure 5.3.
Figure 5.3 Block diagram of GENSAL and GENROU generators
•
GENROU
It is a cylindrical round rotor type and represents the synchronous
thermal power units. The block diagram is as the same of GENSAL.
•
SEXS
It represents the excitation dynamic model and is used for all types of
synchronous generators. The control diagram is shown in Figure 5.4.
Figure 5.4 The control diagram for SEXS excitation dynamic model
24
ELFORSK
•
SATB2A
It is name for stabilizer which is an ASEA power sensitive stabilizer
model and damps the oscillation in electrical output power.
The dynamic control model for this type of stabilizer is illustrated in
Figure 5.5.
Figure 5.5 The dynamic control model for STAB2A
•
VOTHSG is the auxiliary voltage signal
•
HYGOV
It represents the hydro-turbine governor. The block diagram is shown
in Figure 5.6.
Figure 5.6 Block diagram for HYGOV hydro-turbine governor
•
LDFRAL
This model represents the load frequency model and how loads change with
frequency deviation:
= @(
@
)A B = B@(
@
)
where Po and Qo are the active and reactive powers at the nominal
frequency.
1. Updating the Norwegian part of the grid (7 Generators)
2. Updating the Finnish part of the grid ( 6 Generators)
3. Addition of 3WFs in Finland (960 MW)
25
ELFORSK
4. Addition of 12 WFs in Sweden (1920 MW)
5. Addition of WFs in Norway (800 MW)
6. Connecting the south of Norway to bus 4041 by two lines
It is assumed that all the wind turbines are DFIG GE 3.6 MW type. The wind
farms added to the original Nordic-32 power system are presented in Table
5.3.
Table 5.3 The wind farms added to the Nordic-32 grid in each Nordic country
Pgen[MW]
160
160
160
160
160
320
320
Qgen[MVar]
27
8
10
10
10
81
79
Mbase
184
184
184
184
184
368
368
7023
320
81
368
9012
160
9022
160
9032
160
9042
160
9052
160
9062
160
9073
160
9083
160
9093
160
9103
160
9113
160
9123
160
Total installed Wind Power
11
6
9
10
8
-4
27
35
56
49
37
50
184
184
184
184
184
184
184
184
184
184
184
184
Sweden
Finland
Norway
Bus Number
3012
3022
3032
3042
3052
7003
7013
5.2
Total
800 MW
960 MW
1920 MW
3680[MW]
Description of Case 1
Two different operational states are considered, referred to as case 1 and
case 2. The operating condition for case 1 is as follows:
•
High nuclear
•
Low hydro
•
High wind power
26
ELFORSK
The output powers from the nuclear and hydro generating plants are shown in
Tables 5.4 and 5.5, respectively.
Table 5.4 Nuclear power generating plants
Bus Name
BUS4042
BUS4047
BUS4047
BUS4051
BUS4051
BUS4062
BUS4062
400.00
400.00
400.00
400.00
400.00
400.00
400.00
Id
Pgen[MW]
Qgen[Mvar]
MVA
1
1
2
1
2
1
2
660
566
566
629
419
555
555
48
127
127
100
67
0
0
700
600
600
700
700
600
600
Table 5.5 Hydro power generating plants
Bus Name
BUS1012
BUS1013
BUS1014
BUS1021
BUS1022
BUS2032
BUS4011
BUS4012
BUS4021
BUS4031
BUS4041
BUS 5100
BUS 5300
BUS 5400
BUS 5500
BUS 5600
BUS 6000
BUS 6100
BUS 7100
BUS 7101
130.00
130.00
130.00
130.00
130.00
220.00
400.00
400.00
400.00
400.00
400.00
300.00
300.00
300.00
300.00
300.00
300.00
300.00
400.00
400.00
Id
Pgen[MW]
Qgen[Mvar]
MVA
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
264
198
363
424
132
495
473
530
165
325
0
423
651
454
237
680
383
671
225
140
125
38
100
103
35
117
132
25
-30
-40
228
173
-9
0
37
219
-11
343
50
125
800
600
700
600
250
850
1000
800
300
350
300
600
916
633
333
950
466
966
333
333
The hydro power plant located at bus 4011 is considered as swing bus and all
thermal power plants and wind farm operate at their rated capacities. In order
to adopt the low hydro operating condition the following units are removed
and a load flow calculation is performed.
27
ELFORSK
•
Hydro power unit at bus 1021 with nominal rating of 424 MW
•
Hydro power unit at bus 2032 with nominal rating of 495 MW
•
Hydro power unit at bus 7101 with nominal rating of 140 MW
The total active power decreasing from hydro power unites is 1059 MW. The
resulting power generation for the conventional production units is depicted in
Tables 5.6, 5.7 and 5.8.
Table 5.6 Active and reactive power from thermal units in case 1
Thermal Power Plants
PGen (MW)
Bus Bus Name
660
4042 BUS4042 400.00
1132
4047 BUS4047 400.00
1048
4051 BUS4051 400.00
1111
4062 BUS4062 400.00
100
4063 BUS4063 400.00
324
7201
400
689
7203
400
368
7204
400
368
7205
400
0
8002 LIT2
400.00
333
8500
400
377
1042 BUS1042 130.00
189
1043 BUS1043 130.00
6699
Total from Thermal
QGen (Mvar)
85
256
169
0
30
21
62
163
44
0
392
71
100
1391
28
ELFORSK
Table 5.7 Active and reactive power from hydro units in case 1
PGen (MW)
Hydro Power Plants
264
1012 BUS1012 130.00
198
1013 BUS1013 130.00
363
1014 BUS1014 130.00
0
1021 BUS1021 130.00
132
1022 BUS1022 130.00
0
2032 BUS2032 220.00
45
4011 BUS4011 400.00
530
4012 BUS4012 400.00
165
4021 BUS4021 400.00
325
4031 BUS4031 400.00
0
4041 BUS4041 400.00
423
5100
300
651
5300
300
454
5400
300
237
5500
300
680
5600
300
383
6000
300
671
6100
300
225
7100 BUS4071 400.00
0
7101
400
5746
Total from Hydro
Bus
Bus Name
29
QGen (Mvar)
96
45
98
0
84
0
225
58
-30
-40
269
173
-9
0
37
219
-11
343
76
0
1634
ELFORSK
Table 5.8 Active and reactive power from wind farms in case 1
Wind Farms
PGen (MW)
Bus
Bus Name
160
3012 FW_2
3.3000
160
3022 FW_2
3.3000
160
3032 FW_2
3.3000
160
3042 FW_2
3.3000
160
3052 FW_2
3.3000
320
7003 FW_3
3.3000
320
7013 FW_3
3.3000
320
7023 FW_3
3.3000
160
9012 FW_2
3.3000
160
9022 FW_2
3.3000
160
9032 FW_2
3.3000
160
9042 FW_2
3.3000
160
9052 FW_2
3.3000
160
9062 FW_2
3.3000
160
9073 FW_3
3.3000
160
9083 FW_3
3.3000
160
9093 FW_3
3.3000
160
9103 FW_3
3.3000
160
9113 FW_3
3.3000
160
9123 FW_3
3.3000
3680
Total from Wind Farms
QGen (Mvar)
27
74
10
10
10
116
87
81
12
6
9
10
8
-4
27
33
67
58
37
59
736
The amount of wind power as a percentage of the total active power for this
second case is:
WindPowerActivepower
3680MW
=
∗ 100% = 22.82%
TotalActivePower
16125MW
5.3
Description of Case 2
The second operational state to be studied considers a somewhat different
generation mix:
•
Moderate nuclear
•
High hydro
•
High wind power
In this case all the hydro power plants are in service and wind farms are at
their rated powers. Unit 2 of the thermal power generation at bus 4062 is out
30
ELFORSK
of service. All other units are the same as in case 1. The active power
contribution by wind farms in percentage to the total active power for this
case is:
3680MW
WindPowerActivepower
=
∗ 100% = 23%
16257MW
TotalActivePower
31
ELFORSK
6 Simulation results
A number of studies and simulations have been performed to further
understand the impact of synthetic inertia on frequency stability. The details
of the system model are presented in Chapter 5; the simulation results are
presented in this chapter.
6.1
Presumptions
A number of presumptions were made during the system studies:
•
All the wind turbines are DFIG GE 3.6 MW type.
•
One aggregated wind turbine is used to represent all wind turbines
inside a wind farm.
•
The wind speed remains constant during simulation.
•
Wind Inertia module is activated or deactivated for all the wind
turbines simultaneously.
•
The APC module for wind turbines is not activated and therefore,
the wind farms do not contribute to the frequency support after the
new steady-state is reached.
•
When replacing production from conventional units by wind power,
the conventional units remain connected to the grid in the model. In
this way the comparison shows the actual impact of the wind
turbines and not the impact of the reduction in total moment or
inertia (and kinetic energy of the rotating mass) due to the
disconnection of the conventional units.
•
The amount of primary reserve (spinning reserve) is assumed to be
unlimited. This better allows us to study the impact of the synthetic
inertia only.
•
Tripping of load by the under frequency load shedding and of
distributed generation by the under frequency part of the antiislanding detection has not been included in the model. The reason
for this is again to allow the study of the impact of the synthetic
inertia only.
6.2
Contribution of wind turbines to moment of inertia
Modern wind turbines come in two different forms: as a double-fed induction
generator (DFIG) and with a full-power converter. In the latter case, the
rotational speed of the turbine and the frequency of the voltage in the grid
are completely decoupled and there is no contribution to system inertia
possible [32]. With a DFIG there is some coupling possible via the stator
circuit. The impact of DFIGs on the moment of inertia has therefore been
studied specifically in this project.
32
ELFORSK
To illustrate how the introduction of wind power based on DFIGs impacts the
total moment of inertia, the frequency response after the loss of a large
production unit is calculated. A comparison is thereby made for the cases with
and without wind power. The wind turbines are presented as loads with
negative signs for the case without wind farms. This ensures that there are no
other differences in the system, like changes in inertia due to disconnecting of
conventional units or changes in load flow. The contingency triggering the
frequency response is the tripping of the synchronous thermal unit at bus
7203. The frequency excursion is plotted for both cases at bus 4062 and it is
presented in Figures 6.1 and 6.2.
Figure 6.1 Frequency at bus 4062 without WT and with WT but no WI
Figure 6.2 Initial frequency decline at bus 4062
The difference between the two cases is small. Despite the presence of more
production units connected to the system, the frequency excursion only shows
minor difference. The initial rate-of-change of frequency is not observable
different. The nadir of the frequency (the minimum) is only slightly lower for
the system when some wind farms are added to the system.
The conclusion is that wind farms of the kind modelled here (with DFIG
machines) do not contribute to the moment of inertia of the system. When
33
ELFORSK
replacing conventional units with wind power, the total moment of inertia of
the system will become less and the frequency stability will deteriorate.
6.3
Synthetic inertia
A possible solution to prevent deterioration of the frequency stability when
conventional units are replaced by wind power is to equip the wind turbines
with synthetic inertia. The wind-inertia (WI) module of the GE turbine has
been used to study the impact of synthetic inertia on the frequency response
after the loss of a large production unit. The frequency response with and
without synthetic inertia has been compared.
In (2.7) the following expression has been derived for the initial rate-ofchange-of-frequency (ROCOF) after the loss of a production unit of size Δ :
=−
!
5
6
×
7
6
(6.1)
The initial ROCOF depends on the ratio between the size of the unit that is
lost (Δ ) and the rated power of all remaining conventional production
connected to the system (" 0 ).
In reality, the size of the largest production unit (the loss of which is the
“dimensioning failure” for the Nordic grid) will normally not vary. However the
amount of conventional production connected to the grid with show strong
variations through the year. In the existing situation, this is highest during
winter and lowest during summer. In a system with a high percentage of wind
power, low conventional production can occur any time of the year during
periods of high wind-power production.
In the simulations we did not chance the amount of conventional production
connected to the grid. In this case we ensured as much as possible that only
the impact of the synthetic inertia on the frequency response is studied and
not any other differences for instance due to changes in load flow or stability
issues.
The second factor in (6.1) is instead increased by increasing Δ , while keeping
" 0 constant. We will start with a contingency where one unit is tripped,
followed by cases with the loss of three or four units.
6.3.1 Case 1 – 4% loss of production
The first contingency that has been studies is where one unit in the Nordic-32
model is tripped. The initial state is the one discussed as “Case 1” in Chapter
5. This study concerns the tripping one unit at bus 7203 with rated output of
690 MW. The loss of production is 4.3% of the total production (16 125 MW).
The result of simulation comparing the case where wind turbines are equipped
with synthetic inertia (WI) and where they are not is shown in Figure 6.3.
34
ELFORSK
Figure 6.3 Frequency response at bus 4062 with and without synthetic inertia
(WI), case 1, 4% loss of production
The figure shows that the initial decay in frequency is the same in both cases.
When the synthetic inertia becomes active a few seconds after the loss of the
production unit, the drop in frequency is stopped. The minimum frequency is
about 150 mHz higher in the case with synthetic inertia. The presence of
synthetic inertia does however delay the frequency recovery. The new steadystate frequency of 49.8 Hz is reached about 24 s after the loss of the
production unit in the conventional case and about 16 s later when synthetic
inertia is present.
6.3.2 Case 1 – 12% loss of production
The second contingency concerns the loss of a large production unit during an
operational state with low consumption and large wind-power production. The
amount of conventional production connected to the grid will be small in that
case. As mentioned before, this is modelled by assuming the loss of a large
amount of production.
The following loss of production has been studied:
•
Tripping one unit at bus 7203 with rated output of 690 MW
•
Tripping one unit at bus 4042 with rated output of 660 MW
•
Tripping unit 1 at bus 4051 with rated output of 630 MW
The total active-power loss is 1980 MW (12% of total) and the resulting
frequency response with and without synthetic inertia is shown in Figure 6.4.
35
ELFORSK
Figure 6.4 Frequency excursion at bus 4062 for with and without synthetic
inertia (WI), case 1, 12% loss of production
The frequency response is very similar to the one in the first case, with the
exception that the range in frequency variation is larger. Also in this case
does the presence of synthetic inertia raise the minimum frequency but delay
the recovery. The time to recovery is only slightly more than for the loss of
one production unit.
The minimum frequency is raised from 48.45 to 48.75 Hz. As the underfrequency load shedding starts at 48.8 Hz, it would be activated in both
cases. For this specific contingency the presence of synthetic inertia cannot
prevent the activation of the under-frequency load shedding. There are
however cases possible where the minimum frequency is below 49 Hz.
6.3.3 Case 1 – 16% loss of production
An even more severe contingency has been studied, with the loss of four
production units. The following four units have been taken off tripped:
•
Tripping one unit at bus 7203 with rated output of 690 MW
•
Tripping one unit at bus 4042 with rated output of 660 MW
•
Tripping unit 1 at bus 4051 with rated output of 630 MW
•
Tripping unit 1 at bus 4047 with rated output of 566 MW
The total power lost is 2546 MW (16% of total) and the resulting frequency at
bus 4062 for cases with and without synthetic inertia for wind turbines is
shown in Figure 6.5. The general behaviour is again very similar as for the
loss of one and three production units.
36
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Figure 6.5 Frequency excursion at bus 4062 for with and without synthetic
inertia (WI), case 1, 16% loss of production
6.3.4 Comparison
A comparison between the three contingencies studied is made in Table 6.6.
The minimum frequency has been obtained from the data; the time to
recovery has been estimated from the instant at which the frequency versus
time curve becomes flat again.
Table 6.6. Minimum frequency and time to recovery after loss of production,
with and without synthetic inertia (WI)
Loss of production
4.3%
12%
16%
Without WI
Minimum
frequency
49.30 Hz
48.45 Hz
48.25 Hz
Time to
recover
23 s
26 s
26 s
With WI
Minimum
frequency
49.45 Hz
48.75 Hz
48.55 Hz
Time to
recover
38 s
42 s
43 s
From the results shown in the table it is concluded that the synthetic inertia
can support the frequency in the first few seconds after a loss of production,
but that its support is limited in case of a large loss of production. The results
also show that synthetic inertia delays the recovery in all three cases. The
time to recovery is only lightly dependent on the amount of production lost.
6.3.5 Speed and power production of the wind turbines
The functioning of the synthetic inertia is illustrated in more detail in this
section for the worst case (loss of four production units, 16%). The electrical
output power and wind turbine speed for one typical wind farm, the one at
bus 7003, with and without WI capability is presented in Figure 6.6 and 6.7.
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Figure 6.6 Electric power output from wind farm at bus 7003, case 1, 16%
loss of production
Figure 6.7 Speed of Wind turbine at bus 7003, case 1, 16% loss of production
The synthetic inertia becomes active as soon as the frequency drops below
the threshold value, which is defined in the dead-band block of the controller.
The kinetic energy in the rotating parts of the turbine are extracted and
injected into the system: the power flow into the network is more than 1 p.u
(the pre-event value) as long as the speed decreases. The rotor speed
recovers about 30 s after the loss of production and even shows a small
overshoot. The speed overshoot further slows down the voltage recovery.
The electric power production takes much longer to recover to its pre-event
value.
The electrical output power, rotational speed and power system frequency are
shown in Figure 6.8. From this figure, the different stages in the response can
be recognized. During the first stage the active output power increases and
the rotor slows down. The extracted power is limited to the maximum value of
10-15%. The rate of decrease of the rotor speed becomes less so that less
additional power is injected into the grid. About 15 seconds after the loss of
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production, the rotor reaches its lowest speed. The subsequent recovery
requires additional energy which results in the earlier observed delay of the
frequency recovery.
The frequency recovery period is longer when WI module is activated and this
is due to active power demand by wind turbine to restore its speed to the
initial magnitude.
Figure 6.8 Wind farm electrical output power, rotational speed and grid
frequency, case 1, 16% loss of production
6.3.6 Case 2 – Loss of three unit
A second operational state (case 2 in Chapter 5) has been used as a preevent state followed by the loss of three production units (12% of total
production). The following three units are tripped:
•
one unit at bus 7203 with rated output of 690 MW
•
one unit at bus 4042 with rated output of 660 MW
•
unit 1 at bus 4051 with rated output of 630 MW
The total power loss is 1980 MW (12% of total production). The frequency
deviation at bus 4062 for both cases when synthetic inertia of wind turbines is
active or disabled is shown in Figure 6.9.
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Figure 6.9 Frequency response at bus 4062 with and without synthetic inertia
(WI), case 2, 12% loss of production
The impact of the synthetic inertia is very similar to case 1 (compare with
Figure 6.4). The two cases are compared in Table 6.7. The frequency drop is
less in case 2 because there is more hydro power (equipped with frequency
control) present. The recovery time is very similar; the differences are likely
due to the inaccuracy of estimating the time of recover from the plots.
Table 6.7. Minimum frequency and time to recovery after 12% loss of
production, with and without synthetic inertia (WI); two operational states.
Operational state
Case 1
Case 2
Without WI
Minimum
frequency
48.45 Hz
48.70 Hz
Time to
recover
26 s
27 s
With WI
Minimum
frequency
48.75 Hz
48.90 Hz
Time to
recover
42 s
40 s
The power flow from one of the WFs to the grid is presented in Figure 6.10.
The pattern is very similar to the one in Figure 6.6: an initial extra power
injection followed by a long period of reduced injection of power.
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Figure 6.10 Electric power from wind farm at bus 7003, case 2, 12% loss of
production.
The electric output power for one typical hydro power unit is shown in Figure
6.11 for both cases when wind turbine is equipped with and without WI. The
peak value in the electric power output for a hydro power unit is higher when
wind turbines have WI capability. This means that the demand of primary
reserve (“spinning reserve”) is higher when synthetic inertia is present. The
recovery peak to reaccelerate the wind turbines has to be provided by the
conventional generators equipped with frequency control.
Figure 6.11 Electric power for hydro power generator at bus 5600, case 2,
12% loss of production.
6.4
Optimal tuning of parameters in Wind Inertia module
The aim of this section is to optimize the parameters for WI controller module.
From the block diagram for WI of GE 3.6 MW wind turbine it can be observed
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that the adjustable parameters are: dead band, gain and wash-out filter time
constant. In order to get the best value for each of the parameters,
simulations with different values of one parameter have been performed while
other parameters were kept constant.
The criterion for selecting the most optimized value for a parameter is to
obtain best frequency support from both rate of change and deep value point
of view. The result of the simulation is depicted in Figure 6.12 and 6.13.
Figure 6.12 Frequency deviation with different Gain value (the default value
Kwi=10)
Figure 6.13 Frequency deviation with different wash-out time constant (The
default value Twowi=5.5sec)
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The outcome of simulation with different values for Gain and Wash-out time
constant shows that the best results will be obtained from default
recommended values by GE for WI control parameters. Higher values for gain
result in longer frequency recovery.
The tuning of the controller is shown to be a trade-off between the
contribution during the initial seconds after the production loss and the need
for additional power resulting in a delayed frequency recovery.
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7
Conclusion
7.1
Findings
It is shown in this project that wind farms with DFIG machines, according to
the GE model in PSSE, do not contribute to the total moment of inertia in the
system. It was known earlier that also turbines with full-power converter do
not contribute to the system inertia. As a result of this, replacing conventional
production units with wind farms results in a reduction of the total moment of
inertia and thus in a deterioration of the frequency quality.
Installing wind turbines with synthetic inertia is a way of preventing this
deterioration. A number of studies have been performed to study the way in
which synthetic inertia, again according to the GE model in PSSE, impacts the
frequency excursion after the loss of a large production unit. Simulations have
been performed of an augmented Nordic-32 model of the Nordic power
system.
The impact of synthetic inertia, as a function of the loss of production (in
percent of the total production) is shown in the table below. It is clear from
the table that synthetic inertia (WI) can support the frequency in the first few
seconds after a loss of production.
Loss of production
4.3%
12%
16%
Without WI
Minimum
frequency
49.30 Hz
48.45 Hz
48.25 Hz
Time to
recover
23 s
26 s
26 s
With WI
Minimum
frequency
49.45 Hz
48.75 Hz
48.55 Hz
Time to
recover
38 s
42 s
43 s
Accordingly, wind farms are able to contribute to the frequency stability
during the first few seconds after a loss of production by extracting the stored
kinetic energy through synthetic inertia. As a result, it is possible to increase
the minimum frequency and to prevent under-frequency load shedding.
However the contribution from the synthetic inertia might not be sufficient to
prevent a large frequency drop in a severe loss of production.
The simulations also showed some disadvantages of the use of synthetic
inertia: it delays the frequency recovery and it puts higher demand on the
primary reserves.
According to optimal tuning performance studies, the default parameter
values provided by the manufacturer are deemed as optimal parameters.
However the selection of optimal parameter might be a trade-off between the
contribution during the initial seconds after the production loss and the need
for additional power resulting in a delayed frequency recovery.
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7.2
Future work
Further work is needed in the development of control algorithms for synthetic
inertia, where the main challenge is to be able to contribute to the inertia
during the first few seconds without delaying the frequency recovery
unnecessary and without putting extra requirements on the primary reserve.
A fundamental study is needed to find out under which circumstances (e.g.
low consumption in combination with high amounts of wind power) the
activation of synthetic inertia or a similar measure is needed and how often
such circumstances occur. A related study is to do find out when and how
often synthetic inertia in all or a selected number of wind turbines is
insufficient.
The inertia of large production units is rather well known, but the inertia of
smaller units and the contribution of the load to the system inertia can at best
be estimated. To be able to decide about the need for synthetic inertia,
studies are needed to determine the total system inertia including its daily
and seasonal variations.
The activation of the synthetic inertia is based on the detection of a large
deviation from the normal frequency variations. This can be based on rate-ofchange of frequency, exceeding of a threshold in terms of absolute value of
the frequency or exceeding of a threshold in terms of frequency deviation
from a sliding average. Each method has its advantages and disadvantages
and a trade-off is needed between non-activation or late activation and
unnecessary or especially non-wanted activation. Such a trade-off requires a
mapping of the actual frequency variations as they occur in the Nordic
system.
The study presented in this report only covered frequency stability. The
inertia of the system, including its distribution over the system, also plays an
important role with angular stability. The behaviour of synthetic inertia during
angular oscillations needs to be studied.
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8 References
[1]
Ansökan till Vindforsk, On some aspects of power system stability
and grid code requirements relevant for large scale wind power
integration, STRI AB , 2011-04-01
[2]
Guideline for Evaluating the Wind Energy Research Program “
Vindforsk-III”, 2012-02-19
[3]
Minutes from meeting with STRI, Fingrid, Vattenfall
SvenskaKraftnät at STRI office in Gothenburg, 2012-03-21
[4]
ENSTO-E Working Draft, “Requirements for Grid Connection
Applicable to all Generators”, 24 January 2012.
[5]
Swedish
Grid
Codes,
“Affärsverket
svenska
författningssamling”, SvKFS 2005:2, 2005-12-05
[6]
Prabha Kundur, ”Power System Stability and Control”, 1994
[7]
Tony Burton, Nick Jenkins, David Sharpe and Ervin Bossanyi
,”Wind Energy Handbook”, John Wiley and Sons, second edition,
2011
[8]
Math Bollen, Fainan Hassan, ”Integration of Distributed Genration
in the Power System”, 1st edition Wiley, New Jersey, 2011
[9]
Peter Wibæk Christensen, Geman Caludio Tranowski, “Inertia for
Wind Power Plants- State of the art review-Year 2011”
[10]
T. Knüppel, P. Thuring, S. Kumar, M.N. Kragelund, R. Nielsen, K.
André, ”Frequency Activated Fast Power Reserve for Wind Power
Plant Delivered from Stored Kinetic Energy in the Wind Turbine
Inertia”
[11]
Markus Speckmann, André Baier, “Provision of Frequency Control
by Wind Farms” , Fraunhofer IWES, Kassel, Germany
[12]
PSSE/E®, “Program Operation Manual”, Siemens Energy Inc., June
2009
[13]
PSSE/E®, “ Program Application Guide”, Siemens Energy Inc.,
June 2009
[14]
PSSE/E®, “ Model Library”, Siemens Energy Inc., June 2009
[15]
Siemens, “PSS/E Wind Modeling Package for GE 1.5/3.6/2.5 MW
Wind Turbines User Guide”, USA. June 2009
[16]
GE Energy, “ Modeling of GE Wind Turbine-Generators for Grid
Studies”, version 4.3, 2009-04-08
46
and
kraftnäts
ELFORSK
[17]
Nayeem Rahmat Ullah, Torbjörn Thiringer, “Primary Frequency
Control Support from Variable Wind Turbines”,
[18]
Cigré Nordic 32-bus test system
[19]
Affärsveket svenska kraftnäts författningssamling, SvKFS 2001:1,
den 28 december 2001
[20]
Frequency response, National Grid Workgroup Consultation, 18
September 2012, http://www.nationalgrid.com
[21]
Xue Yingcheng, Tai Nengling, System frequency regulation
investigation in doubly fed induction generator (DFIG), WSEAS
Transactions on Power Systems, Vol.7, No.1 (January 2012),
pp.18-26
[22]
Antony Johnson, Simulated Inertia, National Grid, Grid Code
Frequency Response Working Group, 10 September 2010,
http://www.nationalgrid.com
[23]
B. Fox et al., Wind power integration – connection and system
operational aspects, The Institution of Engineering and
Technology, London, UK, 2007,
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Appendix A: GE 3.6 MW Wind Turbine
Parameter Values
The values in the tables are the GE recommended magnitudes.
A.1 GEWTA –GE Wind Turbine Aerodynamics
Table A.1 Constant parameters in GE aerodynamic module
CONs
Value
J
J+1
J+2
J+3
20
0
27
-4
J+4
0
J+5
J+6
J+7
J+8
1.225
52
94
1500
Description
_A`a , Maximum tip speed ratio from Cp-λ curve
_A& , Minimum tip speed ratio from Cp-λ curve
b8c#A`a , Upper limit of pitch angle
b8c#A& , Lower limit of pitch angle
Ta, Time constant of the conversion
smoothening
Ρ, Air density, kg/m3
Radius, Turbine rotor blade radius, m
GearBoxRatio, Gear box ratio
" dde f g
h , Synchronous speed, rpm
A.2 GEWTE1 – GE Wind Turbine Electrical Control
Table A.2 Constant parameters for GE electrical control module
CONs
Value
J
J+1
J+2
J+3
J+4
J+5
J+6
J+7
J+8
J+9
0.15
18
5
0
0
4
0.5
0.05
1.12
0.04
J+10
0.52
J+11
-0.385
J+12
J+13
J+14
1.1
0.02
0.45
Description
8 0 , Filter time constant in voltage regulator, s
i j , Proportional gain in voltage regulator, p.u
ikj , Integrator gain in voltage regulator, p.u
l , Line drop compensation resistance, p.u
m , Line drop compensation reactance, p.u
8n , Filter time constant in torque regulator, s
i , Proportional gain in torque regulator, p.u
ik , Integrator gain in torque regulator, p.u
op , Max. active power in torque regulator, p.u
oq , Min. active power in torque regulator, p.u
Bop , Max. reactive power limit in voltage
regulator, p.u
Boq , Min. reactive power limit in voltage
regulator, p.u
b orp , Maximum active current limit, p.u
8sj , Voltage sensor time constant, s
l op , Max. power order derivative, p.u
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J+15
J+16
J+17
J+18
J+19
J+20
J+21
J+22
J+23
-0.45
5
0.5
0.9
1.1
40
0.5
1.55
0.05
J+24
0.05
J+25
J+26
1
0.15
J+27
0.96
J+28
0.996
J+29
1.004
J+30
1.04
J+31
1
J+32
0.95
J+33
0.95
J+34
0.4
J+35
J+36
J+37
1
0.2
1
J+38
0.25
J+39
-1
J+40
J+41
J+42
11
25
3
J+43
-0.9
J+44
J+45
J+46
8
0.25
10
J+47
1
J+48
J+49
J+50
1.7
1.1
1.25
l
8
oq ,
Min. power order derivative, p.u
, Voltage sensor time constant, s
iuk , Volt-to-MVAr gain, p.u
vokqwx , Min. voltage limit, p.u
vorpwx , Max. voltage limit, p.u
ijk , Volt-to-Vterm gain, p.u
mbBokq , Min. voltage command limit, p.u
mbBorp , Max. voltage command limit, p.u
8j , Lag in WindCONTROL module, s
8 , PELEC filter in power factor angle control
module, s
Fn, Fraction of on-line wind turbines
8`0 , WNDSP3 filter time constant, s
X-axis value of Point A in Frequency response
curve, p.u
X-axis value of Point B in Frequency response
curve, p.u
X-axis value of Point C in Frequency response
curve, p.u
X-axis value of Point D in Frequency response
curve, p.u
Y-axis value of Point A in Frequency response
curve, p.u
Y-axis value of Point B in Frequency response
curve, p.u
Y-axis value of Point C in Frequency response
curve, p.u
Y-axis value of Point D in Frequency response
curve, p.u
PFRmax, Max. WNDSP3, p.u
PFRmin, Min. WNDSP3, p.u
8y , Power command rate limit time constant, s
8xj x , Low voltage power logic sensor time
constant, s
vxj x , Low voltage power logic voltage
breakpoint, p.u
SPDW1, Initial arbitrary wind speed, m/s
SPDWMX, Max. wind speed, m/s
SPDWMN, Min. wind speed, m/s
SPD_LOW, Low rotor speed to trip wind turbine,
m/s
WTTHRES, High wind trip threshold, m/s
EBST, Breaking resistor energy threshold, p.u
KDBR, Breaking resistor controller gain, p.u
Pdbr_MAX, Breaking resistor power error Max.
Limit, p.u
ImaxTD, Converter current thermal limit, p.u
Iphl, Hard active current limit, p.u
Iqhl, Hard reactive current limit, p.u
2t
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J+51
J+52
J+53
J+54
J+55
J+56
J+57
5
0
0
10
0.0025
1
5.5
J+58
0.1
J+59
-1
J+60
0.1
J+61
0
8k
, Reactive droop time constant, s
Kqd, Reactive droop gain, p.u
Xqd, Reactive droop synthesizing reactance, p.u
Kwi, WindInertia gain, p.u
Dbwi, WindInertia frequency deadband, p.u
TIpwi, WindInertia filter time constant, s
Twowi, WindInertia washout time constant, s
Urlwi, WindInertia upward ramp rate limit,
p.u(PBASE)/s
Drlwi, WindInertia upward ramp rate limit,
p.u(PBASE)/s
Pmxwi, WindInertia Max. additional active power,
s
Pmnwi, WindInertia Min. additional active power,
s
z
A.3 GEWTG1 - GE Wind Turbine Generator/Converter
Table A.3 Constant parameters for GE Generator/Converter module
CONs
Value
Description
J
3.6
J+1
0.8
J+2
0.5
J+3
0.9
J+4
1.1
J+5
1.2
J+6
2
J+7
0.4
J+8
0.8
J+9
5
J+10
0.02
Prate (PBASE), Rated power of original unit, MW
Xeq, Equivalent reactance for current injection,
p.u
VLVPL1, Low voltage power logic lower
threshold, p.u
VLVPL2, Low voltage power logic upper
threshold, p.u
GLVPL2, Low voltage power logic gain
corresponding to VLVPL2 in the graph
VHVRCR2, High voltage reactive current logic
(HVRCR) higher voltage limit, p.u
CURHVRCR2, Max. reactive current limit at
VHVRCR2, p.u
VLVACR1, Low voltage active current regulation
(LVACR) logic current limit, p.u
VLVACR2, Low voltage active current regulation
logic voltage threshold, p.u
Rip_LVPL, Rate of LVACR active current change,
p.u (on active current base)/s
TLVPL, Voltage sensor for LVACR time constant, s
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A.4 GEWTP - GE Pitch Control
Table A.4 Constant values in GE aerodynamic module
CONs
Value
Description
J
J+1
J+2
0.3
150
25
J+3
3
J+4
J+5
J+6
J+7
J+8
J+9
30
-4
27
-10
10
1
TP, Time constant of output lag, s
Kpp, Proportional gain of speed PI regulator, p.u
Kip, Integrator gain of speed PI regulator, p.u
Kpc, Proportional gain of current PI regulator,
p.u
Kic, Integrator gain of current PI regulator, p.u
{A& , Lower pitch angle limit, degrees
{A`a , Upper pitch angle limit, degrees
l{A& , Lower pitch angle rate limit, degrees/s
l{A`a , Upper pitch angle limit, degrees/s
Pref, Power reference, p.u
A.5 GEWTT - GE Two Mass Shaft
Table A.5 Constant parameters for GE shaft module
CONs
Value
Description
J
5.74
J+1
0
J+2
1
J+3
0
J+4
2.3
H, Total inertia of the drive train, MW-s/MVA
DAMP, Machine damping factor, p.u (on
PBASE)/ p.u (on Speedbase)
Htfrac, Turbine Inertia fraction
Freq1, first shaft torsional resonant frequency,
Hz
Dshaft, Shaft damping factor
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