13 02 rapport screen

The utilization of synthetic The utilization of synthetic The utilization of synthetic The utilization of synthetic inertia from wind farms and its inertia from wind farms and its inertia from wind farms and its inertia from wind farms and its impact on existing speed impact on existing speed impact on existing speed impact on existing speed governors and system governors and system governors and system governors and system performanceperformanceperformanceperformance

(Part 2 Report of Vindforsk Project V-369)

Elforsk rapport 13:02

Mohammad Seyedi, Math Bollen, STRI January 2013

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The utilization of synthetic The utilization of synthetic The utilization of synthetic The utilization of synthetic inertia from wind farms and its inertia from wind farms and its inertia from wind farms and its inertia from wind farms and its impact on existing speed impact on existing speed impact on existing speed impact on existing speed governors and system governors and system governors and system governors and system performanceperformanceperformanceperformance

(Part 2 Report of Vindforsk Project V-369)

Elforsk rapport 13:02

Mohammad Seyedi, Math Bollen, STRI January 2013

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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, Fingrid Nikkilä Antti-Juhani Fingrid Terje Gjengedal, Statnett Katherine Elkington, Svenska Kraftnät (National Swedish Grid) Johan G. Persson, E.ON Staffan Mared, Vattenfall Kjell Gustafsson, 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 vindkrafts-produktion 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 GE-modellen 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

utan syntetisk tröghet med syntetisk tröghet

Lägsta frekvens

tid att återhämta

Lägsta frekvens

tid att återhämta

4% 49.30 Hz 23 s 49.45 Hz 38 s 12% 48.45 Hz 26 s 48.75 Hz 42 s 16% 48.25 Hz 26 s 48.55 Hz 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 Without synthetic inertia With synthetic inertia Minimum

frequency Time to recover

Minimum frequency

Time to recover

4% 49.30 Hz 23 s 49.45 Hz 38 s 12% 48.45 Hz 26 s 48.75 Hz 42 s 16% 48.25 Hz 26 s 48.55 Hz 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 Background ...................................................................................... 1 1.2 Frequency regulation ......................................................................... 1 1.3 Outline of the report .......................................................................... 2

2 Frequency control in power systems and the impact of wind

power 3 2.1 Basics of frequency control ................................................................. 3 2.2 Impact of wind power ........................................................................ 4 2.3 Synthetic inertia ............................................................................... 6

3 Literature search 8

4 Modelling GE 3.6 MW DFIG wind turbine in PSS/E® 10 4.1 Load flow model of wind turbine........................................................ 11 4.2 Dynamic model of GE 3.6 MW wind turbine ........................................ 12 4.3 Synthetic inertia ............................................................................. 16 4.4 Grid code with regards frequency ranges ........................................... 17

5 Test network 18 5.1 Nordic-32 power system .................................................................. 18 5.2 Description of Case 1 ....................................................................... 26 5.3 Description of Case 2 ....................................................................... 30

6 Simulation results 32 6.1 Presumptions ................................................................................. 32 6.2 Contribution of wind turbines to moment of inertia .............................. 32 6.3 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

6.4 Optimal tuning of parameters in Wind Inertia module .......................... 41

7 Conclusion 44 7.1 Findings ......................................................................................... 44 7.2 Future work .................................................................................... 45

8 References 46

Appendix A: GE 3.6 MW Wind Turbine Parameter Values 48 A.1 GEWTA –GE Wind Turbine Aerodynamics ...................................... 48 A.2 GEWTE1 – GE Wind Turbine Electrical Control ............................... 48 A.3 GEWTG1 - GE Wind Turbine Generator/Converter .......................... 50 A.4 GEWTP - GE Pitch Control ........................................................... 51 A.5 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]:

�� =

��

�� ! (2.2)

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Where �� is the nominal power system frequency, �� is the total

production, � �� is the total consumption and "# the total kinetic energy of rotating mass connected to the system.

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:

# = '()*+,�)

�-./� (2.4)

where � 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 pre-event 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 current-regulated 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

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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

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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.

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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.

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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

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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

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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.

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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

Code

Swedish Grid Code

(SvK) Danish (Energinet.dk)

ENSTO-E

(draft 24 Jan. 2012

Continuous operating

frequency between

continuous operating

voltage

49 Hz to 51 Hz 49.9 HZ to 50.2 Hz 49 Hz to 51 Hz

(for Nordic)

Minimum frequency

between continuous

operating voltage

47.5 Hz 47.5 Hz 47.5 Hz (Nordic)

ROCOF limit Not mentioned

±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 1: 48.8 Hz in 0.15 seconds - Step 2: 48.6 Hz in 0.15 seconds - Step 3: 48.4 Hz in 0.15 seconds - Step 4: 48.2 Hz for 0.15 seconds, and at 48.6 Hz in 15 seconds - Step 5: 48.0 Hz for 0.15 seconds, and at 48.4 Hz in 20 seconds

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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.

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Figure 5.1The original Nordic-32 network

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Table 5.1 Power generating plants, in the Nordic-32 network

No. Bus Bus Name Id PGen

(MW)

QGen

(Mvar)

QMax

(Mvar)

QMin

(Mvar)

Mbase

(MVA)

1 1012 BUS1012 130.00 1 264 125 400 -80 800

Hy

dro

un

its

2 1013 BUS1013 130.00 1 198 38 300 -50 600

3 1014 BUS1014 130.00 1 363 100 350 -100 700

4 1021 BUS1021 130.00 1 424 103 300 -60 600

5 1022 BUS1022 130.00 1 132 35 125 -25 250

6 2032 BUS2032 220.00 1 495 117 425 -80 850

7 4011 BUS4011 400.00 1 473 132 500 -100 1000

8 4012 BUS4012 400.00 1 530 25 400 -160 800

9 4021 BUS4021 400.00 1 165 -30 150 -30 300

10 4031 BUS4031 400.00 1 325 -40 175 -40 350

11 4041 BUS4041 400.00 1 0 228 300 -200 300

12 5100 300 1 423 173 9999 -9999 600

13 5300 300 1 651 -9 9999 -9999 916

14 5400 300 1 454 0 9999 -9999 633

15 5500 300 1 237 37 9999 -9999 333

16 5600 300 1 680 219 9999 -9999 950

17 6000 300 1 383 -11 9999 -9999 466

18 6100 300 1 671 343 9999 -9999 966

19 7100 BUS4071 400.00 1 225 50 9999 -9999 333

20 7101 400 1 140 125 9999 -9999 333

21 4042 BUS4042 400.00 1 660 48 350 0 700 T

he

rma

l u

nit

s 22 4047 BUS4047 400.00 1 566 127 300 0 600

23 4047 BUS4047 400.00 2 566 127 300 0 600

24 4051 BUS4051 400.00 1 629 100 350 0 700

25 4051 BUS4051 400.00 2 419 67 350 0 700

26 4062 BUS4062 400.00 1 555 0 300 0 600

27 4062 BUS4062 400.00 2 555 0 300 0 600

28 4063 BUS4063 400.00 1 100 30 30 0 150

29 1042 BUS1042 130.00 1 377 70 200 -40 400

30 1043 BUS1043 130.00 1 189 100 100 -20 200

31 7201 400 1 324 24 9999 -9999 433

32 7203 400 1 689 62 9999 -9999 866

33 7204 400 1 368 163 9999 -9999 475

34 7205 400 1 368 48 9999 -9999 475

35 8002 LIT2 400.00 1 0 0 9999 -9999 500

36 8500 400 1 333 391 9999 -9999 666

37 3012 FW_2 3.3000 1 160 27 9999 -9999 184

Win

d

Fa

rms

38 3022 FW_2 3.3000 1 160 8 9999 -9999 184

39 3032 FW_2 3.3000 1 160 10 9999 -9999 184

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40 3042 FW_2 3.3000 1 160 10 9999 -9999 184

41 3052 FW_2 3.3000 1 160 10 9999 -9999 184

42 7003 FW_3 3.3000 1 320 81 9999 -9999 368

43 7013 FW_3 3.3000 1 320 79 9999 -9999 368

44 7023 FW_3 3.3000 1 320 81 9999 -9999 368

45 9012 FW_2 3.3000 1 160 11 9999 -9999 184

46 9022 FW_2 3.3000 1 160 6 9999 -9999 184

47 9032 FW_2 3.3000 1 160 9 9999 -9999 184

48 9042 FW_2 3.3000 1 160 10 9999 -9999 184

49 9052 FW_2 3.3000 1 160 8 9999 -9999 184

50 9062 FW_2 3.3000 1 160 -4 9999 -9999 184

51 9073 FW_3 3.3000 1 160 27 9999 -9999 184

52 9083 FW_3 3.3000 1 160 35 9999 -9999 184

53 9093 FW_3 3.3000 1 160 56 9999 -9999 184

54 9103 FW_3 3.3000 1 160 49 9999 -9999 184

55 9113 FW_3 3.3000 1 160 37 9999 -9999 184

56 9123 FW_3 3.3000 1 160 50 9999 -9999 184

Total Generation Capacity by Hydro power units 7232 MW

Total Generation Capacity by Thermal power units 6698 MW

Total generation Capacity by Wind Farms 3680 MW

Total Generation Capacity by all units 17611 MW

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Figure 5.2 Modified Nordic-32 grid including the augmented Norwegian and Finnish part.

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2

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1

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5

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0.0

5

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5

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146. 3

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0.0

5

200.0

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7201

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402. 0

0. 0

44.6

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2032

1011

1013

1014

1012

4012

4011

7100

7102

7101

72007201

7203

7205

7204

40464042

4022

1022

4021

4031 4032

2031

2032

4041 4044

42

46

47

43

1044

1042

1043

1041 1045

41

4045

4051

4061

61

4062

62

4063

8500

63

61

1021

5300

6100

6000

5400

5500

5100

5101

5501

5503

5602

5401

6001

5600

5103

5102

5301

5601

5402

8001 8002

4043

400kV

130kV

220kV

130kV

400kV

220kV

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23

Table 5.2 rated active and reactive powers of loads

No. Bus Bus Name Pload (MW) Qload (Mvar)

1 41 BUS41 130.00 551 128

2 42 BUS42 130.00 408 126

3 43 BUS43 130.00 918 239

4 46 BUS46 130.00 714 194

5 47 BUS47 130.00 102 45

6 51 BUS51 130.00 816 253

7 61 BUS61 130.00 510 112

8 62 BUS62 130.00 306 80

9 63 BUS63 130.00 602 256

10 1011 BUS1011 130.00 204 80

11 1012 BUS1012 130.00 306 100

12 1013 BUS1013 130.00 102 40

13 1022 BUS1022 130.00 286 95

14 1041 BUS1041 130.00 612 200

15 1042 BUS1042 130.00 306 80

16 1043 BUS1043 130.00 235 100

17 1044 BUS1044 130.00 816 300

18 1045 BUS1045 130.00 714 250

19 2031 BUS2031 220.00 102 30

20 2032 BUS2032 220.00 204 50

21 4045 BUS4045 400.00 200 0

22 4046 BUS4046 400.00 -300 0

23 4051 BUS4051 400.00 250 0

24 4063 BUS4063 400.00 -200 0

25 5100 300 1160 204

26 5300 300 59 3

27 5400 300 27 0

28 5500 300 360 38

29 5600 300 915 99

30 5603 300 410 171

31 6100 300 892 326

32 7100 BUS4071 400.00 348 50

33 7101 400 348 50

34 7201 400 306 70

35 7203 400 306 70

36 7203 400 300 0

37 7204 400 612 140

38 7205 400 306 70

39 8001 LIT 400.00 0 0

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40 8500 400 340 333

41 8500 400 204 0

Total 15658 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

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• 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:

= @( ��@)AB = 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)

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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

Bus Number Pgen[MW] Qgen[MVar] Mbase Total

No

rwa

y

3012 160 27 184

800 MW

3022 160 8 184

3032 160 10 184

3042 160 10 184

3052 160 10 184

Fin

lan

d 7003 320 81 368

960 MW 7013 320 79 368

7023 320 81 368

Sw

ed

en

9012 160 11 184

1920 MW

9022 160 6 184

9032 160 9 184

9042 160 10 184

9052 160 8 184

9062 160 -4 184

9073 160 27 184

9083 160 35 184

9093 160 56 184

9103 160 49 184

9113 160 37 184

9123 160 50 184

Total installed Wind Power 3680[MW]

5.2 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

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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 Id Pgen[MW] Qgen[Mvar] MVA

BUS4042 400.00 1 660 48 700

BUS4047 400.00 1 566 127 600

BUS4047 400.00 2 566 127 600

BUS4051 400.00 1 629 100 700

BUS4051 400.00 2 419 67 700

BUS4062 400.00 1 555 0 600

BUS4062 400.00 2 555 0 600

Table 5.5 Hydro power generating plants

Bus Name Id Pgen[MW] Qgen[Mvar] MVA

BUS1012 130.00 1 264 125 800

BUS1013 130.00 1 198 38 600

BUS1014 130.00 1 363 100 700

BUS1021 130.00 1 424 103 600

BUS1022 130.00 1 132 35 250

BUS2032 220.00 1 495 117 850

BUS4011 400.00 1 473 132 1000

BUS4012 400.00 1 530 25 800

BUS4021 400.00 1 165 -30 300

BUS4031 400.00 1 325 -40 350

BUS4041 400.00 1 0 228 300

BUS 5100 300.00 1 423 173 600

BUS 5300 300.00 1 651 -9 916

BUS 5400 300.00 1 454 0 633

BUS 5500 300.00 1 237 37 333

BUS 5600 300.00 1 680 219 950

BUS 6000 300.00 1 383 -11 466

BUS 6100 300.00 1 671 343 966

BUS 7100 400.00 1 225 50 333

BUS 7101 400.00 1 140 125 333

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.

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• Hydro power unit at bus 1021 with nominal rating of 424 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

Bus Bus Name PGen (MW) QGen (Mvar)

4042 BUS4042 400.00 660 85

4047 BUS4047 400.00 1132 256

4051 BUS4051 400.00 1048 169

4062 BUS4062 400.00 1111 0

4063 BUS4063 400.00 100 30

7201 400 324 21

7203 400 689 62

7204 400 368 163

7205 400 368 44

8002 LIT2 400.00 0 0

8500 400 333 392

1042 BUS1042 130.00 377 71

1043 BUS1043 130.00 189 100

Total from Thermal 6699 1391

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Table 5.7 Active and reactive power from hydro units in case 1


Hydro Power Plants

1012 BUS1012 130.00 264 96

1013 BUS1013 130.00 198 45

1014 BUS1014 130.00 363 98

1021 BUS1021 130.00 0 0

1022 BUS1022 130.00 132 84

2032 BUS2032 220.00 0 0

4011 BUS4011 400.00 45 225

4012 BUS4012 400.00 530 58

4021 BUS4021 400.00 165 -30

4031 BUS4031 400.00 325 -40

4041 BUS4041 400.00 0 269

5100 300 423 173

5300 300 651 -9

5400 300 454 0

5500 300 237 37

5600 300 680 219

6000 300 383 -11

6100 300 671 343

7100 BUS4071 400.00 225 76

7101 400 0 0

Total from Hydro 5746 1634

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Table 5.8 Active and reactive power from wind farms in case 1

Wind Farms


3012 FW_2 3.3000 160 27

3022 FW_2 3.3000 160 74

3032 FW_2 3.3000 160 10

3042 FW_2 3.3000 160 10

3052 FW_2 3.3000 160 10

7003 FW_3 3.3000 320 116

7013 FW_3 3.3000 320 87

7023 FW_3 3.3000 320 81

9012 FW_2 3.3000 160 12

9022 FW_2 3.3000 160 6

9032 FW_2 3.3000 160 9

9042 FW_2 3.3000 160 10

9052 FW_2 3.3000 160 8

9062 FW_2 3.3000 160 -4

9073 FW_3 3.3000 160 27

9083 FW_3 3.3000 160 33

9093 FW_3 3.3000 160 67

9103 FW_3 3.3000 160 58

9113 FW_3 3.3000 160 37

9123 FW_3 3.3000 160 59

Total from Wind Farms 3680 736

The amount of wind power as a percentage of the total active power for this second case is:

WindPowerActivepowerTotalActivePower = 3680MW

16125MW ∗ 100% = 22.82%

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

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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:

WindPowerActivepowerTotalActivePower = 3680MW

16257MW ∗ 100% = 23%

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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 anti-islanding 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.

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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

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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-of-change-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.

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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 steady-state 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 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.

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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 under-frequency 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:





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.

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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 Without WI With WI Minimum


Minimum frequency

Time to recover

4.3% 49.30 Hz 23 s 49.45 Hz 38 s 12% 48.45 Hz 26 s 48.75 Hz 42 s 16% 48.25 Hz 26 s 48.55 Hz 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 pre-event 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 Without WI With WI Minimum


Minimum frequency

Time to recover

Case 1 48.45 Hz 26 s 48.75 Hz 42 s Case 2 48.70 Hz 27 s 48.90 Hz 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 Without WI With WI

Minimum frequency

Time to recover

Minimum frequency

Time to recover

4.3% 49.30 Hz 23 s 49.45 Hz 38 s 12% 48.45 Hz 26 s 48.75 Hz 42 s 16% 48.25 Hz 26 s 48.55 Hz 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-of-change 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 and 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 kraftnäts 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

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[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 Description

J 20 _A`a, Maximum tip speed ratio from Cp-λ curve J+1 0 _A&�, Minimum tip speed ratio from Cp-λ curve J+2 27 b8c#A`a, Upper limit of pitch angle J+3 -4 b8c#A&�, Lower limit of pitch angle

J+4 0 Ta, Time constant of the conversion

smoothening J+5 1.225 Ρ, Air density, kg/m3 J+6 52 Radius, Turbine rotor blade radius, m J+7 94 GearBoxRatio, Gear box ratio J+8 1500 "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 Description

J 0.15 8�0, Filter time constant in voltage regulator, s J+1 18 i�j, Proportional gain in voltage regulator, p.u J+2 5 ikj, Integrator gain in voltage regulator, p.u J+3 0 l�, Line drop compensation resistance, p.u J+4 0 m�, Line drop compensation reactance, p.u J+5 4 8n�, Filter time constant in torque regulator, s J+6 0.5 i��, Proportional gain in torque regulator, p.u

J+7 0.05 ik�, Integrator gain in torque regulator, p.u J+8 1.12 op, Max. active power in torque regulator, p.u J+9 0.04 oq, Min. active power in torque regulator, p.u

J+10 0.52 Bop, Max. reactive power limit in voltage

regulator, p.u

J+11 -0.385 Boq, Min. reactive power limit in voltage

regulator, p.u J+12 1.1 borp, Maximum active current limit, p.u J+13 0.02 8sj, Voltage sensor time constant, s J+14 0.45 lop, Max. power order derivative, p.u

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J+15 -0.45 loq, Min. power order derivative, p.u J+16 5 8� 2t�, Voltage sensor time constant, s

J+17 0.5 iuk, Volt-to-MVAr gain, p.u J+18 0.9 vokqwx, Min. voltage limit, p.u J+19 1.1 vorpwx, Max. voltage limit, p.u J+20 40 ijk, Volt-to-Vterm gain, p.u J+21 0.5 mbBokq, Min. voltage command limit, p.u J+22 1.55 mbBorp, Max. voltage command limit, p.u J+23 0.05 8j, Lag in WindCONTROL module, s

J+24 0.05 8�, PELEC filter in power factor angle control

module, s J+25 1 Fn, Fraction of on-line wind turbines J+26 0.15 8̀ 0, WNDSP3 filter time constant, s

J+27 0.96 X-axis value of Point A in Frequency response

curve, p.u

J+28 0.996 X-axis value of Point B in Frequency response

curve, p.u

J+29 1.004 X-axis value of Point C in Frequency response

curve, p.u

J+30 1.04 X-axis value of Point D in Frequency response

curve, p.u

J+31 1 Y-axis value of Point A in Frequency response

curve, p.u

J+32 0.95 Y-axis value of Point B in Frequency response

curve, p.u

J+33 0.95 Y-axis value of Point C in Frequency response

curve, p.u

J+34 0.4 Y-axis value of Point D in Frequency response

curve, p.u J+35 1 PFRmax, Max. WNDSP3, p.u J+36 0.2 PFRmin, Min. WNDSP3, p.u J+37 1 8y, Power command rate limit time constant, s

J+38 0.25 8xj�x, Low voltage power logic sensor time

constant, s

J+39 -1 vxj�x, Low voltage power logic voltage

breakpoint, p.u J+40 11 SPDW1, Initial arbitrary wind speed, m/s J+41 25 SPDWMX, Max. wind speed, m/s J+42 3 SPDWMN, Min. wind speed, m/s

J+43 -0.9 SPD_LOW, Low rotor speed to trip wind turbine,

m/s J+44 8 WTTHRES, High wind trip threshold, m/s J+45 0.25 EBST, Breaking resistor energy threshold, p.u J+46 10 KDBR, Breaking resistor controller gain, p.u

J+47 1 Pdbr_MAX, Breaking resistor power error Max.

Limit, p.u J+48 1.7 ImaxTD, Converter current thermal limit, p.u J+49 1.1 Iphl, Hard active current limit, p.u J+50 1.25 Iqhl, Hard reactive current limit, p.u

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J+51 5 8k�z�, Reactive droop time constant, s J+52 0 Kqd, Reactive droop gain, p.u J+53 0 Xqd, Reactive droop synthesizing reactance, p.u J+54 10 Kwi, WindInertia gain, p.u J+55 0.0025 Dbwi, WindInertia frequency deadband, p.u J+56 1 TIpwi, WindInertia filter time constant, s J+57 5.5 Twowi, WindInertia washout time constant, s

J+58 0.1 Urlwi, WindInertia upward ramp rate limit,

p.u(PBASE)/s

J+59 -1 Drlwi, WindInertia upward ramp rate limit,

p.u(PBASE)/s

J+60 0.1 Pmxwi, WindInertia Max. additional active power,

s

J+61 0 Pmnwi, WindInertia Min. additional active power,

s

A.3 GEWTG1 - GE Wind Turbine Generator/Converter

Table A.3 Constant parameters for GE Generator/Converter module

CONs Value Description J 3.6 Prate (PBASE), Rated power of original unit, MW

J+1 0.8 Xeq, Equivalent reactance for current injection,

p.u

J+2 0.5 VLVPL1, Low voltage power logic lower

threshold, p.u

J+3 0.9 VLVPL2, Low voltage power logic upper

threshold, p.u

J+4 1.1 GLVPL2, Low voltage power logic gain corresponding to VLVPL2 in the graph

J+5 1.2 VHVRCR2, High voltage reactive current logic

(HVRCR) higher voltage limit, p.u

J+6 2 CURHVRCR2, Max. reactive current limit at

VHVRCR2, p.u

J+7 0.4 VLVACR1, Low voltage active current regulation

(LVACR) logic current limit, p.u

J+8 0.8 VLVACR2, Low voltage active current regulation

logic voltage threshold, p.u

J+9 5 Rip_LVPL, Rate of LVACR active current change,

p.u (on active current base)/s J+10 0.02 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 0.3 TP, Time constant of output lag, s

J+1 150 Kpp, Proportional gain of speed PI regulator, p.u J+2 25 Kip, Integrator gain of speed PI regulator, p.u

J+3 3 Kpc, Proportional gain of current PI regulator,

p.u J+4 30 Kic, Integrator gain of current PI regulator, p.u J+5 -4 {A&�, Lower pitch angle limit, degrees J+6 27 {A`a, Upper pitch angle limit, degrees J+7 -10 l{A&�, Lower pitch angle rate limit, degrees/s J+8 10 l{A`a, Upper pitch angle limit, degrees/s J+9 1 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 H, Total inertia of the drive train, MW-s/MVA

J+1 0 DAMP, Machine damping factor, p.u (on

PBASE)/ p.u (on Speedbase) J+2 1 Htfrac, Turbine Inertia fraction

J+3 0 Freq1, first shaft torsional resonant frequency,

Hz J+4 2.3 Dshaft, Shaft damping factor

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13 02 rapport screen

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