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ES13030
Examensarbete 30 hpMar 2013
Grid Code Compliance – Wind Farm Connection
Martin Västermark
Teknisk- naturvetenskaplig fakultet UTH-enheten Besöksadress: Ångströmlaboratoriet Lägerhyddsvägen 1 Hus 4, Plan 0 Postadress: Box 536 751 21 Uppsala Telefon: 018 – 471 30 03 Telefax: 018 – 471 30 00 Hemsida: http://www.teknat.uu.se/student
Abstract
Grid code compliance – wind farm HVDC connection
Martin Västermark
A rapid development of offshore wind power is planned in GB as a part to fulfil theEU2020 targets. 25 GW wind power capacity has been awarded to developers in ninedifferent offshore zones outside the coast of UK. VSC-HVDC transmission isexpected to be a both technical and economical favourable solution for transmittingthe power into the main grid. This study investigates if such a transmission solutioncould comply with the regulatory framework in UK.
Vattenfall and Scottish Energy Renewable will be part of this development and havebeen awarded the rights to develop 7200 MW of wind capacity outside the cost ofEast Anglia as a part of the offshore expansion plans in UK. The zone is broken downto several projects. The first project is called East Anglia ONE and this project is usedas a reference case in this study.
The GB Grid Code has been broken down into four areas, voltage and frequencyvariations; fault ride through requirements, active power control and reactive powercontrol. Load flow calculations and dynamic simulations are designed to investigatecompliance of each area. Further, simulations to investigate the interaction betweenthe wind turbines and the offshore converter stations where done.
A model representing East Anglia ONE was built in PSS/E and used to investigate gridcodes compliance by load flow calculations and dynamic simulations. Data from earlierstudies at Vattenfall was used to get a good representation of the wind park. A modelrepresenting a HVDC-transmission solution was provided by ABB.
The results from load flow calculations and simulations show that a HVDC-solutioncan comply with the investigated parts of the grid codes. The limiting factor seems tobe the capability to inject enough reactive power to the gird at small voltage dipsduring normal operation. This capability can, however, be enhanced with the righttap-changer settings at the onshore converter transformer.
ISSN: 1650-8300, UPTEC ES13030Examinator: Kjell PernestålÄmnesgranskare: Mikael BergqvistHandledare: Urban Axelsson
Populärvetenskaplig sammanfattning på svenska
Havsbaserad vindkraft förväntas växa i Storbritannien som en del i landets åtagande
att uppfylla EU:s 2020-mål. Rättigheter till 25 GW vindkraft har tilldelats
vindkraftsexploatörer i nio olika zoner utanför Storbitanniens kust. VSC-HVDC
förväntas vara både tekniskt och ekonomiskt fördelaktigt för att transmittera kraften
från vindkraftparken och in till land. Denna studie undersöker om en sådan
transmissionslösning skulle kunna uppfylla det regelverk (grid codes) som finns i
Storbritannien för att få ansluta vindkraft till stamnätet.
Vattenfall och Scottish Energy Renewable har blivit tilldelade rättigheterna att bygga
totalt 7200 MW havsbaserad vindkraft utanför East Anglia. Projektet har delats upp i 6
delprojekt, vart och ett på 1200 MW. Det första projektet, East Anglia ONE, har
använts som ett referensfall i denna studie. Byggstart för projektet är satt till 2016 och
bara detta delprojekt kommer bli en av världens största vindkraftparker om det
genomförs.
Regelverket i Storbritanien har i denna studie brutits ned i fyra delar: spännings- och
frekvensavvikelser, överleva fel i stamnätetet, frekvenskontrol och spänningskontrol.
Frekvensavvikelser uppstår vid en missmatch av produktion och last som kan uppstå
vid t.ex. produktionsbortfall. Små spänningsavvikelser kan också bero av last eller
produktionsborfall men också på grund av fel i avlägsna delar av nätet. Det är viktigt
att produktionsanläggningen klarar av att fortsätta sin normala produktion vid dessa
typer av fel. Simuleringarna av kombinerade frekvens och spänningsavvikelser visar
att parken kan klara av dessa förändingar i enlighet med regelverket.
En produktionsanläggning måste också klara av fel i nätet. Dessa kan sänka
spänningen vid omriktarstationen till nära 0 volt. Kraven för hur länge felen överlevas
beror på hur mycke spänningen sänks vid anslutningspunkten samt på felets typ.
Regelverket specifiserar inte bara att anläggningen ska överleva felet, det finns även
krav på att den aktiva effektproduktionen ska återvända inom en sekund efter felet
samt krav på att leverera reaktiv effekt medan felet pågår. Simuleringarna antyder att
en den föreslagna HVDC-lösningen klarar av att hantera kraven för fel i nätet.
Vidare finns det krav på frekvensstöd. I normalfallet ska vindkraftverken reglera ned
sin aktiva effekt produktion vid en nätfrekvens på 50.4 Hz. Emellertid finns det krav
på att anläggningen ska kunna klara av att vara ett mer aktivt stöd och klara av att
stötta frekvensen vid både över och underfrekvens i nätet. Denna typ av
frekvensreglering kallas delta-reglering och kräver att vindkraftverken i detta
kontrolschema spiller vind för att klara av att öka produktionen vid underfrekvens. Ett
enkelt frekvensregleringskontrol för vindkraftverken har skrivits inom projektet och
med detta klarar anläggningen att uppfylla kraven.
En anläggning ska kunna stötta spänningen i nätet genom att leverera eller konsumera
reaktiv effekt. Genom att leverera reaktiv effekt till nätet höjs spänningen i
anslutningspunkten och på liknande sätt kan spänningen i anslutningspunkten sänkas
genom att anläggningen konsumerar reaktiv effekt. Att leverera tillräkligt med reaktiv
effekt i nätet vid små spänningsdippar är, enligt simuleringarna, den begränsande
faktorn med en HVDC-transmissionslösning. Simuleringarna visar att
omriktarstationen har svårt att leverera tillräkligt med reaktiv effekt.
Omriktarstationens förmåga att leverera tillräkligt med reaktiv effekt vid små
spänningsdippar kan dock öka genom att sänka den initala spänningen vid
omriktarstationen genom lindningskopplaren på tranformatorn. Med hjälp av detta kan
regelverket uppfyllas.
Aktiv effekt levererad till nätet vid olika inställningar av lindningskopplaren vid
transformatorn på land
Utöver kraven i regelverket har även simuleringar i nätet vid vindkraftparken gjorts.
Dessa simuleringar har undersökt hur omriktarstationen till havs sammspelar med
vindkraftverken vid fel. Simuleringarna visar inte på några tecken på onormalt höga
spänningar, effektpendlingar eller problem med transient stabilitet.
Sammanfattningsvis visar denna studie att en vindkraftpark med en VSC-HVDC
transmissionslösning kan uppfylla det regelverk som finns för att få ansluta
anläggningar till stamnätet.
0
0,2
0,4
0,6
0,8
1
1,2
0 0,1 0,2 0,3 0,4 0,5
R1=1.0000
R1=1.0125
R1=1.0250
R1=1.0375
R1=1.0500
Q-Req
Q (pu)
P (pu)
Grid code compliance – wind farm HVDC connection
Vattenfall
From Date Serial No.
Vattenfall Research and Development AB BA R&D - Wind & Ocean power
2012-02-28 U 13:12
Author/s Security class Project No.
Västermark, Martin Official version PR.270.3.14.2
Customer Reviewed by
Tor, Sven Erik Axelsson, Urban
He, Ying
Issuing authorized by
Neimane, Viktoria
Key Word No. of pages Appending pages
Grid Codes, HVDC, Offshore Wind, East Anglia, PSS/E
49 22
Uppsala University
Program Date Serial No.
Master of Science in Engineering
Specialisation: Energy Systems Engineering
2012-02-28 ES13030
Author/s Supervisor Instructions Evaluator
Examiner
Västermark, Martin Axelsson, Urban Bergqvist, Mikael Pernestål, Kjell
Table of Contents
Page
Abstract 3
Populärvetenskaplig sammanfattning på svenska 4
Abbreviations 1
1 INTRODUCTION 2
1.1 Background 2
1.2 Purpose 3
1.3 Reference Case – East Anglia ONE 3
1.4 Previous Work at Vattenfall 4
1.5 Report content 4
2 METHODOLOGY 5
2.1 Simulation methodology 5
3 MODEL OF EAST ANGLIA ONE 6
3.1 Model design 6
3.2 The HVDC transmission system 7
3.3 Collection network 9
3.4 Wind turbines 10
3.5 Zero- and negative phase sequence impedances 10
4 REGULATORY FRAMEWORK FOR OFFSHORE WIND PARKS 10
4.1 Regulatory framework in United Kingdom 11
4.2 Regulatory framework within the European Union 11
5 LOAD FLOW CALCULATIONS 12
6 OPERATION DURING NORMAL VOLTAGE AND FREQUENCY
DEVIATIONS 13
6.1 Frequency and voltage requirements in GB 14
6.2 Frequency and voltage requirements in ENTSO-E grid code 15
6.3 Study cases for frequency and voltage variations 15
6.3.1 Set 6.1 – Dynamic simulations, frequency and voltage 15
7 FAULT RIDE THROUGH REQUIREMENTS 16
7.1 FRT requirements in GB 17
7.2 FRT requirements in ENTSO-E grid code 18
7.3 Study cases for FRT-requirements 20
7.3.1 Set 7.1 – Dynamic simulations, FRT Mode A 20
8 ACTIVE POWER CONTROL 22
8.1 Requirements for active power control in GB Grid Code 23
8.2 Requirements for active power control in ENTSO-E Grid Code 24
8.3 User defined models in active power control 26
8.4 Study cases for active power control 27
8.4.1 Set 8.1 – Dynamic simulations frequency response capability 27
8.4.2 Set 8.2 – Dynamic simulations, step response and islanding operation28
9 REACTIVE POWER CONTROL 29
9.1 Requirements for reactive power control in GB Grid Code 29
9.2 Requirements for reactive power control in ENTSO-E Grid Code 33
9.3 User written models for reactive power control 33
9.4 Study cases for reactive power control 33
9.4.1 Set 9.1 – Converter reactive capability in load flow 34
9.4.2 Set 9.2 – Dynamic performance of onshore converter 35
9.4.3 Set 9.3 – Power flow calculations at different active power output and
initial tap settings 36
9.5 Potential error in the provided HVDC-model 37
10 FAULTS AT THE OFFSHORE GRID AND CONVERTER TRIPS 38
10.1 Study cases for the offshore grid and converter stations 38
10.1.1 Set 10.1 – Offshore grid faults 39
10.1.2 Set 10.2 - Trip of converter 43
11 CONCLUSIONS 44
11.1 Main result 44
11.2 Reflection on the grid codes 45
11.3 Reflection on simulation results 45
11.4 Further studies 45
12 REFERENCES 47
Figures Page
Figure 1 One of the layout suggestion for East Anglia ONE 4
Figure 2 PSS/E model of East Anglia ONE, 600 MW 6
Figure 3 PSS/E model of converter station 8
Figure 4 P-Q diagram of an HVDC-light converter 8
Figure 5 Relationship between dynamic and load flow model 9
Figure 6 Ownership for a large offshore wind power parks 11
Figure 7 Future development of national grid codes without cross-border framework
12
Figure 8 Minimum active power transferred during frequency deviations 14
Figure 9 – Simulations for evaluating frequency-voltage window 15
Figure 10 Simulations outcomes, Set 6.1 Simulation 2 16
Figure 11 Voltage duration profile specified by FRT requirements, Mode B 17
Figure 12 Examples of voltage-duration specified by FRT requirements, Mode B 18
Figure 13 Min and Max FRT profile, ENTSO-E and GB grid code 19
Figure 14 FRT-simulation outcome 22
Figure 15 Active power response requirements in the GB grid code 23
Figure 16 Exampel of ENTSO-E grid code 25
Figure 17 User written PSS/E model for active power control 27
Figure 18 Frequency response volume tests 28
Figure 19 Active power response, test 18 28
Figure 20 System islanding and step response tests 29
Figure 21 Reactive power transfer capability requirements in a P-Q diagram 30
Figure 22 Voltage – Reactive Power envelop 31
Figure 23 Reactive power control requirements 31
Figure 24 Reactive power response requirements 32
Figure 26 PSS/E user model for reactive power control 33
Figure 27 Test parameters of Set 9.1 34
Figure 28 P-Q diagram that shows the result of tests preformed in 9.1 35
Figure 29 Setup of simulations in set 9.2 35
Figure 30 Example of a simulation outcome in Set 9.2 36
Figure 31 Results of tests of Set 9.2 36
Figure 32 Dynamic simulation outcome of set 9.3 37
Figure 33 Reactive power output at Pwind=570 MW and Pwind=600 MW 38
Figure 34 Extension of model during offshore simulations 39
Figure 35 Offshore grid extension 40
Figure 36 Test 5, offshore converter and wind turbine 42
Figure 37 Outcome of simulation 5, onshore converter and DC system 43
Figure 38 Simulation output, onshore converter trip 44
Tables Page
Table 1 Frequency operation requirements ................................................................. 14
Table 2 Simulation setup in for operation in frequency-voltage window.................... 16
Table 3 FRT simulation, Mode A ................................................................................ 20
Table 4 Simulation outcome, Mode A ......................................................................... 20
Table 5 FRT-simulations, Mode B .............................................................................. 20
Table 6 Simulation outcome, Mode B ......................................................................... 21
Table 7 Frequency sensitive mode as suggested by ENTSO-E and in GB.................. 25
Table 8 Limited Frequency Sensitive mode as suggested by ENTSO-E and in GB ... 25
Table 9 Articles evaluated with regards to reactive power control ............................. 29
Table 10 Definition of intersection in Figure 21 ......................................................... 30
Table 11 Parameters for offshore grid faults ............................................................... 41
Appendices Number of Pages
APPENDIX Pp
A Data for PSS/E models 3
B PSS/E user models 2
C Data – short current from national grid (Only available at
Vattenfall in Solna).
-
D Simulation outcomes 17
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Abbreviations
BC – GB Grid Code, Balancing Code
CC – GB Grid Code, Connection Conditions
DFIG – Double Fed Induction Generator
DMOL - Designed Minimum Operating Level
ENTSO-E - European Network of Transmission System Operators for Electricity
FSIG – Fixed Speed Induction Generator
FSM – Frequency Sensitive Mode
FRT – Fault Ride Through
HVAC – High Voltage Alternating Current
HVDC – High Voltage Direct Current
LFSM – Limited Frequency Sensitive Mode
OC – GB Grid Code, Operation Code
OFTO – Offshore Transmission System Owner
PPM – Power Park Module
STC – System Operator - Transmission Owner Code
TSO – Transmission System Operator
VSC – Voltage Source Converter
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1 Introduction
1.1 Background
Coal and gas has been the foundation of power production within Europe for many
years. Threats of global warming and security of supply issues have put pressure of
restructuring the power system. The European Union has decided to increase the
energy production to from renewable sources to 20% of the total consumption by 2020
as part of the EU2020-targets [1].
Wind power will play a significant role to achieve the 2020-targets [2]. However,
integration of wind power into the power system will challenge the system operators
to maintain reliability and stability. Grid codes are therefore developed and updated by
transmission system operators (TSOs) [3].
Today, double fed induction generators (DFIG) and variable speed, full converters are
the dominating design for new turbines. These are better equipped to handle
connection requirements, especially fault ride through requirements [4]. This makes
the design equipped to comply with grid codes in Europe and North America [3], [5].
However, since each wind farm has its unique characteristics it needs to be analysed
and optimised case by case [6].
The grid code compliance is not only affected by the wind turbine design but also by
the transmission system, which transfer the power to the grid. There are mainly two
kinds of transmission alternatives for a large offshore wind park, high voltage
alternating current (HVAC) and high voltage direct current (HVDC). An HVAC
transmission system has usually lower investment cost compared to an HVDC
solution. HVDC tend to be competitive at long distances from shore due to low losses
in the HVDC transmission cables and that HVAC-offshore solution needs heavy
reactive power compensation [7].
An HVDC transmission system could mainly be designed in two ways. Current source
converters (CSC) are used in conventional HVDC technology which is based on
thyristor technology. The alternative is HVDC technology with voltage-source
converter (VSC), which can be beneficial to overall system performance. VSC
converter technology is better equipped to rapidly control both active and reactive
power [8] A VSC-HVDC system is more compact due to the absence of external
reactive power control devices. However, the VSC technology has lower power
ratings, higher losses and is more expensive [9]. There has been important advances in
the voltage-source converters since 2000 and it is seen as an attractive option for
offshore wind connection and the first connection was commissioned in 2010 [10].
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Several studies have been written on VSC-HVDC transmission system and their
ability to fulfil grid codes. For example [6] and [9] studies VSC-HVDC in
combination with double fed induction generators (DFIG) generators while [11] and
[12] investigates the combination of VSC-HVDC and fixed speed induction
generators.
However, no study has systematically evaluated the ability of a VSC-HVDC
transmission system to fulfil the requirements in the GB grid code. The study
presented in this thesis makes an effort to fill that gap by presenting a systematically
analyse of the GB grid code combined with load flow analyses and dynamic
simulations of a wind park and a VSC-HVDC transmission system. Further, this study
investigates the interaction between the HVDC-station and full converter wind
turbines at the offshore grid during faults.
1.2 Purpose
The purpose of the study is to investigate how an HVDC transmission solution for
East Anglia ONE could comply with the grid code in GB as well as the pan-European
grid code suggested by ENTSO-E.
1.3 Reference Case – East Anglia ONE
GB has identified electricity generated by offshore wind farms as a key to achieve
their part of the EU2020 [13] and up to 18 GW wind could be deployed by 2020 [14].
Vattenfall has together with ScottishPower Renewables been awarded to develop 7200
MW of offshore wind capacity outside the coast of East Anglia [15]. The first project,
East Anglia ONE, is planned to have an installed capacity of 1200 MW and the
construction is planned to start in 2016 [16]. One suggested design is to use 7MW full-
converter wind turbines and a transmission solution with two VSC-HVDC offshore
transmission systems, transferring 600MW each. The layout is shown in Figure 1.
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Figure 1 One of the layout suggestion for East Anglia ONE
1.4 Previous Work at Vattenfall
Both HVAC and HVDC transmission solutions have been suggested for East Anliga
ONE. However, earlier simulation studies regarding the East Anglia ONE project has
focused on AC transmission solutions. A reactive compensation study for an AC
transmission solution at 220 kV has been done [17]. Further, a grid code compliance
study regarding the static reactive power requirements for an AC solution is done [18],
where the main alternative was on 132kV and 150kV AC transmission cables.
Different solutions for a collection network at 66kV have been investigated in [19],
which mainly focuses on active power losses for different layouts.
1.5 Report content
The grid code is broken down to four areas of investigation in line with [3]. These
areas are:
Grid frequency and voltage variations
Fault ride through requirements
Active power control/Frequency support
Reactive power control/Voltage support
A summary of the grid codes in GB regarding each area is presented in this study.
Further, a summary of the proposed future requirements in the suggested pan-
European grid code are also presented regarding each area. Sets of tests to investigate
grid code compliance are presented after the grid code summaries and the main results
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of the load flow calculations and simulations are described. The study does also
contain simulations for a fifth area:
Offshore grid faults and converter trips
These simulations are not necessary to fulfil grid codes but still interesting for a wind
power developer to ensure that the wind turbines and the VSC-HVDC station can
handle faults in the offshore grid.
Other areas of the grid code, such as protection requirements, planning and
administrative procedure are considered outside the scoop of the study.
2 Methodology
Requirements for East Anglia ONE are identified within GB grid code, Issue 2 [20]
and the suggested pan-Europen network code for generators [21]. Both GB and
ENTSO-E provides associated documents [22],[23],[24], which have been used as
guidelines while identifying requirements. Four areas are identified as relevant for this
project operation during normal frequency and voltage variations, fault ride through
capability, active power control and reactive power control.
A model of half the wind farm (i.e 600MW) was developed in PSS/E. Electrical data
has primarily been taken from other studies regarding East Anglia ONE Offshore
Wind. Secondarily, electrical data were derived from other studies or in discussion
with Vattenfall and ABB who provided the VCS-HVDC model for the study.
A number of relevant load flow calculation and simulation studies are identified with
help of the grid code and associated documents. These tests are grouped into several
sets associated with one of the four identified areas of relevance. These tests are
performed by load flow calculations or by dynamic simulations in the created PSS/E
model. Load flow calculations and dynamic simulations are done in order to
investigate the fulfilment of the GB grid code since the pan-European grid code still is
a draft.
2.1 Simulation methodology
Voltage and frequency needs to be adjusted during the grid code compliance study.
Desired voltage is achieved with swing bus settings at the static power flow
calculations. During dynamic simulations the bus voltage is manipulated by adding a
fixed shunt at the bus. The fixed shunt adjust the reactive power delivered to the bus,
consequently the bus voltage is adjusted.
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Frequency is manipulated by a used created model for PSS/E. The main grid is
represented by a large rotating synchronous generator, GENCLS model in PSS/E,
during the dynamic simulations. One state in the GENCLS model is Δspeed, which
can be used to manipulate the frequency. The user model changes the derivate of the
Δspeed parameter and changes thereby the frequency of the grid. See Fel! Hittar inte
referenskälla. for a full description of the user model.
3 Model of East Anglia ONE
The PSS/E model of East Anglia ONE is built for one of the two HVDC-transmission
systems according to the suggested design presented in Figure 1. The model can be
seen in Figure 2. As seen in the figure, the main grid is reduced to a single generator.
This generator acts as a swing bus, i.e. it keeps the system in balance during load flow
calculations by absorbing all active and reactive power.
Figure 2 PSS/E model of East Anglia ONE, 600 MW
3.1 Model design
The PSS/E model has been a simplification of the planned layout of East Anglia ONE.
The simplifications are done to make the model more transparent and some times due
to lack of data.
Modelling only one of the two HVDC-transmission systems for this layout implies
that possible interaction between the two transmission systems is not handled in the
study. Further, the collection network is only modelled implicitly and the wind
turbines are lumped together and are represented by two large turbines. The
simplifications make that interaction between turbines is outside the scope of the
modelling work. The consequences are expected to be limited since neither reactive
power nor voltage variations are transferred through a HVDC-transmission system.
Consequently, voltage variations onshore or reactive power requirements at the grid
entry will not affect the offshore AC-transmission system or the wind turbines. The
offshore grid is extended in chapter 10 to better capture interaction between turbines
and the offshore converter during offshore faults or converter trips.
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The onshore grid is, as mentioned above, represented by a swing bus and is not
modelled extensive. The single generator is supposed to give a good enough
representation of the strong grid. No governor or exciter system is modelled at the
generator representing the main grid. This ensures that the simulation results are
depended on the HVDC-transmission system and the wind turbines and not the swing
bus itself. It might, however, be a less realistic representation of the onshore grid. The
single generator representation does also obstruct realistic faults in the main grid.
Shunts of different size are however considered to be a good enough representation of
faults that can occur in the main grid.
3.2 The HVDC transmission system
The model of the HVDC transmission system is provided by ABB. The load flow
model is represented by two separate busses, each with a transformer, a generator and
a fixed shunt connected to each bus. The compound model is supposed to give a good
representation of the characteristic of a VSC-HVDC system [25]. A HVDC-model
from the PSS/E library with data provided by Siemens was evaluated early in the
project but something in the model created a “Visual Fortran run-time error” which
caused the system to crash.
The filter acts as a shunt due to its capacitive characteristics. The size of the filter, and
thereby the amount of reactive power provided to the grid by the filter, is not
determined within this report. The reason is that power quality and over frequency are
hard to study with the used simulation tool, PSS/E, since it only simulates the 50Hz
system. However, the filter is important when investigating the voltage support
because of capacitive characteristics. A filter with less capacitive characteristics would
increase the ability of the transmission system to consume reactive power but hamper
the ability to inject reactive power into the grid.
The generators represent the converter and the fixed shunts are a representation of
AC-filters, see Figure 3. The losses in the HVDC transmission system are set by the
difference of the active power generated by the two generators. ABB suggest that new,
multilevel VSC-HVDC converters have losses at about 1 % of the transferred power
[26].
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Converterer
Filter
Converterer
PSS/E representation of HVDC converter station
Schematic HVDC converter station
representation
Figure 3 PSS/E model of converter station
P and Q of the generator representing the converter station, need to be chosen within
the P-Q diagram provided by ABB. This diagram is found in Figure 4 and is valid for
the whole voltage range specified in the GB grid code (0.95-1.05 pu).
Figure 4 P-Q diagram of an HVDC-light converter [24, p.21]
Data for the HVDC system are provided by ABB for a standard 800 MW solution.
Relevant parameters (e.g. the Sbase, P and Q) are scaled to better represent a 600 MW
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transmission solution. The active power capacity is determined to 600 MW which
leads to Sbase= 653 MVA. Other relevant parameters can be found in Fel! Hittar inte
referenskälla..
Both converters are set to be in voltage control mode. The offshore converter has a
frequency control setting, which implies that the offshore converter manages the
frequency offshore by absorbing the same amount of power that is produced by the
wind turbines. The onshore converter controls the DC-voltage since the offshore
converter controls the active power transmitted through the system.
The load flow model of the HVDC transmission system is replaced during dynamic
simulations. ABB has provided a dynamic model of the transmission system which is
called CABBO2 and represent two converter stations connected with a DC line. The
relationship between dynamics and static power flow can bee seen in Figure 5.
Figure 5 Relationship between dynamic and load flow model [24, p.7]
One important feature of the HVDC transmission system during dynamic simulations
is the chopper. The chopper can consume power if the wind turbines produce more
power than the onshore converter can deliver to the grid, for example during fault in
the main grid. The chopper can, according to ABBs default setting, consume full
power during 2 seconds and is placed at the DC side of the offshore converter.
According to ABB, “This version of the model implementation is verified by
comparison with identical test cases in PSCAD/EMTDC.” [24, p.1]
3.3 Collection network
The collection network is modelled according to characteristics shown in earlier
studies of East Anglia ONE. PSS/E represents a branch with a π-equivalent and
electrical data for the collection network branch is chosen in accordance with the
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results given in [18]. The active losses in the collection network are estimated to be
1/3 of active losses in transformers during full load [19].
3.4 Wind turbines
The wind turbines are aggregated into two generation units, where each represents 300
MW generation. The lumped representation of wind turbines are in accordance with
PSS/E manual [27]. The wind turbine dynamics is represented by two standard models
in the PSS/E library, one mechanical model and one electrical (WT4G2, WT4E2).
Combined, the two models represent the generator and the electrical control model of
a wind turbine connected to the grid via a power converter. The aggregated turbines
are in voltage control mode. A discussion of offshore control system is found in
Chapter 10.
3.5 Zero- and negative phase sequence impedances
During unsymmetrical faults, zero- and negative phase sequence impedances are
needed. These impedances are implemented at the onshore grid since unsymmetrical
faults only are applied on the onshore grid in this project. The impedances where put
to provide fault currents according to data provided by National Grid. These data can
be found in Fel! Hittar inte referenskälla..
4 Regulatory framework for offshore wind parks
Both technological development and market-oriented economic theories put a pressure
to liberalise the power market rose in the 1980-1990th. According to International
Energy Agency a liberalisation of the energy sector offers significant potential
benefits. Improved efficiency in production, better allocation of resources, lower
prices and improved risk allocation are some mentioned examples. The principle
structure of a liberalised electricity sector is a wholesale market for electric power
generation while transmission and distribution is managed through regulated
monopolies [28].
Liberalised markets for electricity require regulation to enable a co-ordinated power
system. All generation units need, at least to some extent, to be able to support the
voltage and manage the frequency deviations. These requested abilities are regulated
by a set of codes which commonly is called grid codes or network codes. A generation
unit needs to fulfil the grid codes in order to connect to the grid. National Grid argues
that the grid code is designed to “permit the development, maintenance and operation
of an efficient, co-ordinated and economical system for the transmission of electricity,
to facilitate competition in the generation and supply of electricity and to promote the
security and efficiency of the power system as a whole.” [29]
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4.1 Regulatory framework in United Kingdom
In accordance with the segregation of power generation and power transmission in a
liberalised power sector, GB has decided to separate the ownership of the offshore
wind park and the offshore transmission system. The first module is the Power Park
Module (PPM) which consists of the wind turbines and the collection network and is
owned by a wind power developer. The second module is the offshore transmission
system which is owned by an Offshore Transmission Owner (OFTO) [30].
There are two different codes that set the requirements for an offshore wind park to
connect to the grid. The Grid Code puts requirements of the PPM to fulfil at nodes A
and E in Figure 6. System Operator - Transmission Operator Code (STC) specifies the
requirements for the offshore transmission system and also requirements on the PPM
and the offshore transmission system combined that should be fulfilled at the grid
entry (node A, Figure 6).
The combined requirements of the wind park and the offshore transmission system
suggest a coordinated design. It is common that a wind power developer constructs
and designs both the wind park and the offshore transmission system. The offshore
transmission system is transferred to an OFTO in a later stage. The Grid Code has
been adapted for this procedure and does accordantly specify the requirements for the
offshore transmission system before it is handed over to an OFTO. It is therefore
enough to only evaluate the Grid Code in order to cover the requirements for
connecting the wind farm to the grid.
Figure 6 Ownership for a large offshore wind power parks [29, p.5]
4.2 Regulatory framework within the European Union
A genuine internal market for energy is a goal of the European Union. Wholesale
markets for energy (electricity & gas) are seen as instrument for reasonable pricing,
granting market access for utilities and increased security of supply [31]. One step of
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creating the internal market for electricity is to harmonize the grid codes between the
member countries.
Pan-European grid codes have been formulated by ENTSO-E which is the cooperation
body for electric TSOs in Europe. It is interesting to note that the power to form rules
of future European legislation was given to a non-political organisation. This does not
follow the common practice within EU and is puzzling with regards to the earlier
observed resistance to let go of national control over energy issues [32].
The characteristic of power systems differ between regions in Europe which makes it
inappropriate to have the same requirements for generators all over Europe. The grid
code suggested by ENTSO-E is therefore formed as a framework where the purpose is
to bring forward a set of coherent requirements. This is done in order to ensure a
homogenous evolution of national practises [23].
Figure 7 Future development of national grid codes without cross-border
framework [22, p. 6]
The grid code suggested by ENTSO-E regards requirements at the offshore grid entry
point. The performance of the power park module can therefore not be enhanced by a
HVDC-connection which especially is a concern for reactive power control. However,
the suggested requirements for reactive power control for offshore power park
modules in GB are relatively easy to cope with.
ENTSO-E is in the process of forming a pan-European grid code specially designed
for HVDC transmission. A draft should be presented soon [33] but is not available for
the moment. The similarities of the GB transmission code (STC-code, [34]) and grid
code does however indicate that the requirements will be very similar at the onshore
interference point. Codes that regulate the interaction between the wind turbines and
the offshore converter station might however be in included in the code.
5 Load flow calculations
An AC transmission system operates in a free flow mode. This means that the power
flows in a non-hierarchical grid, where the flow is governed by the principle of least
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impedance. Power flow calculations can be made to understand how the power flows
between busses, from the generation to the loads.
A power flow calculation is the calculation of voltage magnitude and voltage angle at
each bus in a power system. Both active and reactive power flow can be computed
when the voltage magnitude and angle is known, which also reveals losses in the
system. Since two variables are unknown for each bus (except the slack bus), the
equation system requires two equations for each bus. This is obtained bellow
Equation 1 Load flow equations
P = active power load
Q = reactive power load
V = voltage magnitude
δ = voltage angle
θkn = impedance angle
Ykn = admittance between bus k and bus n
Ykk = all admittance connected to bus k
This equation system is non-linear and numerical solutions are often required. Most
power flow computation programs let the user choose between different numerical
solution methods, two common ones are Newton-Raphson and Gauss-Seidel.
6 Operation during normal voltage and frequency deviations
There is a normal frequency operating window in which the frequency and voltage can
vary during normal operations, at least for some time. The facility should disconnect if
the frequency is outside the window. However, if the voltage is outside the window,
the fault ride through (FRT) requirements come into force and specify the required
behaviour of the power park and its offshore transmission system. FRT requirements
are highlighted in Chapter 7.
The following grid codes are investigated in this chapter
GB Grid Code
ENTSO-E Grid Code
CC.6.1, CC.6.3 Article 8(1), Article 10(2)
N
n
knnknknkk
N
n
knnknknkk
VYVQ
VYVP
1
1
)sin(0
)cos(0
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6.1 Frequency and voltage requirements in GB
The frequency window is between 47-52Hz [CC.6.1.3], where Table 1 specifies how
long a PPM needs to be able to operate at grid frequency deviations.
Table 1 Frequency operation requirements
Frequency Operation time
51.5-52.0 Hz 15 min
51.0-51.5 90 min
49.0-51.0 Continuously
47.5-49.0 90 min
47.0-47.5 20 s
A reduction in active power transfer to the main grid is allowed when the
frequency drops bellow 49.5 Hz. The requirements for a DC converter station
connected to the main grid decreases according to a linear function from 100%
at 49.5 Hz to 95% at 47.0Hz [CC.6.3.3 (b)], which is shown in
Figure 8.
Figure 8 Minimum active power transferred during frequency deviations
[CC.6.3.3(d)]*.
* Figure is slightly modified
The voltage window is between 0.95 and 1.05 pu [CC.6.1.4] and the facility should be
able to provide full active power within the voltage window. Voltage outside the
voltage window is classified as faults and requirements regarding faults are presented
in Chapter 7.
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6.2 Frequency and voltage requirements in ENTSO-E grid code
Frequency requirements within the ENTSO-E are identical with the GB grid code
provided by National Grid [Article 8(1b)]. The voltage levels shows, however a more
demanding variation in the ENTSO-E code. The variation, which only concerns the
wind turbines, states that the turbine needs to operate in the voltage span between 0.9
and 1.1 pu [Article 20(1)]. This requirement will hopefully be mitigated in the
upcoming ENTSO-E HVDC-connection code since voltage dips from the main grid
are blocked by an HVDC-transmission solution.
6.3 Study cases for frequency and voltage variations
Four cases are identified within the frequency-voltage window; high voltage and high
frequency, high voltage and low frequency, low voltage and high frequency and
finally low voltage and low frequency. This is seen in Figure 9.
Figure 9 – Simulations for evaluating frequency-voltage window
6.3.1 Set 6.1 – Dynamic simulations, frequency and voltage
The wind turbines generate full power production, i.e. total 600MW, during the
simulation. This simulation is only meant to show that the facility can operate in the
frequency-voltage window. Therefore, no frequency control is implemented and the
onshore converter is set to reactive power control instead of voltage control.
Frequency control and voltage control are discussed in Chapter 8 and 9. The
frequency and voltage is at start 50 Hz and 400kV and is then changed to achieve the
desired deviations within 2 seconds with a linear increase or decrease of the
parameters. The parameters can be seen in Table 2.
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Table 2 Simulation setup in for operation in frequency-voltage window
Simulation nr Frequency
deviation
(ΔHz)
Voltage
deviation
(Δpu)
1 2 0.05
2 -3 0.05
3 -3 -0.05
4 2 -0.05
The grid code is fulfilled according to the simulation outcomes. An example,
Simulation 2, is presented in Figure 10. See Fel! Hittar inte referenskälla..1 for the
outcome of the complete set of test.
Figure 10 Simulations outcomes, Set 6.1 Simulation 2
7 Fault ride through requirements
Voltage can collapse or be reduced by fault in the grid. A DC converter station
connected to the grid should be able to ride through a fault in the main grid without
disconnecting. The facility should also provide as much reactive power as possible to
the grid during the fault and quickly restore the active power output when the fault is
cleared. The following grid codes are investigated in this chapter
Active power (MW) Reactive power (Mvar)
Frequency (Hz) Voltage (pu)
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GB Grid Code
ENTSO-E Grid Code
CC.6.3, CC.A.4, CP.A.3.5
STC.K.3.1
Article 11(3)
7.1 FRT requirements in GB
Fault Ride Through (FRT) requirements are separated into two categories, Mode A
and Mode B. Mode A represent a full three phase fault or any unbalanced fault where
the remote bus voltage is down to zero volt, and the fault duration is up to 140ms
[CC.6.3.15]. The Mode B category includes voltage drops outside the normal
operation limit (i.e. ±0.05 pu) but where voltage stays above zero V. The voltage
duration requirements are dependent on how large the voltage drop is. Figure 11
shows voltage levels of balanced voltage dips in Mode B and associated duration on
the main grid [CC.6.3.15.1].
Figure 11 Voltage duration profile specified by FRT requirements, Mode B
[CC.6.3.15.1(b)(i)]
Figure 11 should not be interpretated as a voltage profile; it shows the FRT duration
for different drops magnitude. A voltage drop down to 30 % should, for example, be
managed for at least 384ms and a voltage drop down to 50% should be managed for at
least 710ms [CC.A.4]. These examples can be seen in Figure 12
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Figure 12 Examples of voltage-duration specified by FRT requirements, Mode B
[21, p. 23]
A power park developer can choose if the FRT requirement should be fulfilled on the
HV-side of the transformer to the transmission grid or at the low voltage side of the
offshore platform transformer [CC.6.3.15]. In the case of an OFTO, the offshore
transmission grid needs to comply with the FRT requirements at the onshore grid
entry, i.e. on the high voltage side of the transformer connecting to the main grid
[STC.K.3.1]. This implies that the choice described in CC.6.3.15 is irrelevant for this
study, the transmission system and the power park needs to handle FRT-requirements
at the onshore grid entry point.
Three requirements are put upon a wind park and the transmission system regarding
FRT requirements. The park should not disconnect during the fault, the park should
restore the active power output to 90 % of the level before the fault within 1 second
from fault clearance and the facility should inject as much reactive power as possible
during the fault.
7.2 FRT requirements in ENTSO-E grid code
Since FRT is a more local phenomenon, harmonizing pan-European rules are less
relevant. The ENTSO-E grid code transfers therefore a lot of decisions regarding
FRT-capabilities to the relevant TSOs, in accordance with the document ENTSO-E
perspective on Requirements for Generators [23]. The window, in which the TSO are
able to choose from, is however quite narrow. A large wind farm should withstand a
voltage collapse down to zero between 140-250ms [Article 11(3)]. The FRT-profile in
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the suggested ENTSO-E code is linear to 85% within 1.5-3 seconds, as shown in
Figure 13. The figure does also illustrate the time requirements for a voltage drop to
30% which is calculated according to Equations 2, 3 and 4.
Figure 13 Min and Max FRT profile, ENTSO-E and GB grid code
Equation 2 FRT time according to GB grid code at V=0.3 pu
Equation 3 Minimum FRT time according to ENTSO-E grid code at V=0.3 pu
0 0.5 1 1.5 2 2.5 3 3.5 4 4.5
ENTSO-E min profile ENTSO-E max profile UK Grid code
85 % of
nominal
voltage
msVt
tttVVV
ttVt xx
384)15.03.0(15.08.0
14.02.114.0)(
2.1,)()(
3.0
000
msVt
ttV
tVVt xx
53085.0
5.13.0)(
]5.1[,)(
3.0
0
msVt
ttV
tVVt xx
106085.0
0.33.0)(
]0.3[,)(
3.0
0
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Equation 4 Maximum FRT time according to ENTSO-E grid code at V=0.3 pu
Figure 13 shows the requirements for a large wind farm in the suggested grid code by
ENTSO-E. The requirements for a large wind farm connected to the main grid through
a HVDC transmission system has to be revised when ENTSO-E publish their grid
code suggestion for HVDC-transmissions [33].
7.3 Study cases for FRT-requirements
7.3.1 Set 7.1 – Dynamic simulations, FRT Mode A
According to [CP.A.3.5] a simulation of a solid three phase should be done at the
“nearest point” of the main grid. Since there is no representation of the main grid in
the PSS/E model the fault has been applied on the swing bus which is connected to the
HVDC grid entry by a 2 ohm reactance line. The DC converter should operate at full
active power output and “maximum leading reactive power import” is the simulation
setup for Mode A faults and zero reactive power transfer for Mode B faults.
[CP.A.3.5.1]. Transient stability, reactive power delivered during the fault and active
power restoration after clearance is evaluated for this mode. The setup can be seen in
the tables below.
Table 3 FRT simulation, Mode A
Simulation Fault type Fault time (s)
Simulation 1 Three phase 0.140
Simulation 2 Phase-phase 0.140
Simulation 3 Phase-phase-
ground
0.140
Simulation 4 Phase-ground 0.140
Table 4 Simulation outcome, Mode A
Simulation
results
Resulting votlage on
bus at grid entry
(pu)
Reactive power
delivered during
fault (pu)
Result 1 0.004 0
Result 2 0.75 0.3
Result 3 0.25 0.12
Result 4 0.65 0.27
All Mode A simulations were transient stabel and the initial power output was reached
within less than 0.1 seconds after fault clearance.
Table 5 FRT-simulations, Mode B
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Simulation Fault type Voltge at grid
entry
Fault time (s)
Simulation 6 Three phase 0.3 0.384
Simulation 7 Three phase 0.5 0.710
Simulation 8 Three phase 0.8 2.5
Simulation 9 Three phase 0.85 180
Table 6 Simulation outcome, Mode B
Simulation
results
Reactive
power
delivered
during fault
Results 6 0.15
Results 7 0.2
Results 8 0.33
Results 9 0.33
All Mode B simulations were transient stabel and the initial power output was reached
within less than 0.1 seconds after fault clearance. The reactive power delivered in
simulation 8 and 9 was limited due to the Qmax limitation in the user written voltage
control model.
The transmission system and the wind park managed to fulfil the GB grid code in the
set. However, the wind turbines needs to decrease their power output during
simulation nine since the chopper has limited possibilities to reduce energy output
during such a long period. An example of the simulation outcomes can be seen in
Figure 14, see Fel! Hittar inte referenskälla..2 for further examples.
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Figure 14 FRT-simulation outcome
8 Active power control
Active power control at a wind turbine is mainly done by aerodynamic torque control.
The speed of the rotor can be controlled in a full converter turbine, which can be used
to maintain favourable tip speed ratio with changing wind speed or to reduce the
efficiency of the rotor which reduces the active power output from the turbine. Pitch
control of the blades to change the aerodynamic torque on the rotor. The pitch angle,
and thus the power output, can be changed to a desired value in approximately 3
seconds. [35] Wind power trubines can, however, shut down significantly faster
during an emergency shudown, especially if a chopper or a cobar is installed.
The purpose of active power control is to support the grid to restore frequency
deviations. The following grid codes are investigated.
GB Grid Code
ENTSO-E Grid Code
BC.3.5, BC.3.7, CC.6.3,
CC.A.3
Article 8(1), Article 10(2)
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8.1 Requirements for active power control in GB Grid Code
The wind farms are required to have active power control, hence to have a flexible
operating range. The maximum output of a wind farm is referred to as the Registered
Capacity (RC) and the minimum output is referred to as Designed Minimum
Operating Level (DMOL). The wind farm should be able to control the active power
output between the RC to the DMOL. The DMOL should be at least 55 % of the
registered capacity [CC.A.3.3] but is usually approximately 20 % according to the
guidance notes for power park developers. With an intermittent power source, such as
wind, the frequency response could be limited by the available power in the wind.
This limitation does not violate the grid code. [22].
Requirements for active power control process are mainly stated in the balancing
code, section 3 [BC3] and are divided into two operating modes in the GB grid code.
A wind park operates normally in Limited Frequency Sensitive Mode (LFSM). This
mode requires active power response when the frequency exceeds 50.4 Hz. The
generating unit is required to reduce power output with at least 2 % of the registered
capacity per 0.1 Hz [BC.3.7.2] which is equal to a droop of 10 %.
National Grid can request that large wind farms (over 50 MW) provide primary,
secondary and/or high frequency response. Doing so, the plant enters the Frequency
Sensitive Mode, which put stricter requirements regarding active power control
[BC.3.5.4]. In Frequency Sensitive Mode (FSM) the plant should be able to adjust its
active power control outside a deadband of ± 0.015 Hz with a droop of 3-5 %
[CC.6.3.7]. Both LFSM and FSM are illustrated in Figure 15
Figure 15 Active power response* requirements in the GB grid code
*Droop=4%
All the available power in the wind is utilized during normal operation. The wind park
can consequently not support low frequency event since the power output is at
maximum and therefore is impossible to increase further. National Grid can, however,
Frequency support (UK)
-25%
-20%
-15%
-10%
-5%
0%
5%
10%
15%
20%
25%
49 49,5 50 50,5 51
Frequency (Hz)
Δ P
FSM
LSFM
Min response
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order a wind park to not utilize all available power in the wind which then enables the
wind park to provide frequency support. This is called delta-regulation and can be
used during frequency instability.
While the reactive power control mostly puts strict time limits, the active power
control requirements are vaguer. “As much as possible of the proportional reduction in
Active Power output […] must be achieved within 10 seconds”. [BC.3.7.1(c)]
8.2 Requirements for active power control in ENTSO-E Grid Code
The ENTSO-E grid code defines three different modes with regards to active power
output; (1) limited frequency sensitive mode – overfrequency (LFSM-O), (2) limited
frequency sensitive mode – underfrequency (LFSM-U) and (3) frequency sensitive
mode (FSM). A large wind farm needs to be able to act in all three modes, however
the limited frequency sensitive mode – underfrequency will most certainly never be
used for a wind park.
Within LFSM-O, the positive deadband should be adjustable between 0.2 and 0.5 Hz
and the droop should be adjustable between 2-12% in active power outside the dead
band. The actual deadband and droop should be decided by the relevant TSO (i.e.
National Grid). [Article 8.1(c)]
Within FSM, the positive deadband should be decided by the relevant TSO (i.e
National Grid) within a range between ±250mHz. The droop should be adjustable
between 2-12 %, the same range as the LFSM .The frequency deviations treated by
frequency sensitive mode are restricted by a maximum power change ΔP/PRC of 1.5-
10 % [Article 10.2(c)]. FSM translates into LFSM mode at the LFSM threshold
[Article 8.1(c)].
An example of the ENTSO-E grid code is shown in Figure 16, with parameters
according to Table 7 and Table 8.
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Figure 16 Exampel of ENTSO-E grid code
Table 7 Frequency sensitive mode as suggested by ENTSO-E and in GB
Frequency Sensitive Mode
(FSM)
Figure 16 Range specified in ENTSO-E grid code
Active power response
(ΔP/PRC)
10 % Adjustable between 1.5-10 %
Droop 4 % Adjustable between 2-12 %
Deadband 0 ± 250 mHz*
* The deadband should be decided by the relevant TSO (i.e. National Grid) within the
range that is specified by ENTSO-E
Table 8 Limited Frequency Sensitive mode as suggested by ENTSO-E and in GB
Limited Frequency
Sensitive Mode (LFSM)
Figure 16 Range specified in ENTSO-E grid code
Active power range
(max-min)
Pref ±25% Pmax-Designed Minimum Operating Level
Droop 4% Adjustable between 2-12 %
Frequency threshold 50.4 Hz Adjustable between 50.2-50.5 Hz
There is an inconsistency between the grid code suggested by ENTSO-E and the
current grid code in the FSM-control scheme. The grid code suggested by ENTSO-E
limits the sensitive frequency response between 1.5% and 10% of the registered
capacity, while no such limitations exist at the GB grid code. Consequently, the GB
grid code requires a response outside the limits specified by ENTSO-E.
Frequency support (ENTSO-E)
-25%
-20%
-15%
-10%
-5%
0%
5%
10%
15%
20%
25%
49 49,5 50 50,5 51
Frequency (Hz)
Δ P
FSM
LFSM - O/U
Min response,
set by relevant
TSO
c
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8.3 User defined models in active power control
One design challenge for the facility is that the HVDC-transmission system does not
transfer the onshore frequency to the offshore grid by default. The information about
the onshore frequency needs however to be translated to the turbines. There are two
possible solutions. One is to measure the frequency onshore and let the offshore
HVDC-converter mirror the onshore frequency to the offshore grid. The frequency
could then be measured at each turbine and a frequency control system could be
designed to act in accordiance with the grid code requirements. Another solution
would be to measure the frequency onshore and send digital signals to each wind
turbine; such a system can be part of a power park controller (PPC). The generic wind
model used in this study has no frequency control system and the later option is
therefore used in this study. This is also the option used in Thenet, another Vattenfall
wind farm. Two models have been created for the frequency support study, one for
frequency manipulation and one for active power control of the model of the generic
wind turbines.
The model for manipulating the frequency onshore is named CLSFRQ. The model is
used as a turbine governor model for a GENCLS turbine (i.e. the swing bus onshore in
this project). The model does not simulates an actual behaviour of the turbine, instead
it forces the frequency of the GENCLS turbine (and thereby the synchronous network)
to change with a desired ramp rate until it reach a desired total change in frequency.
The second user model is used to control active power output from the generic wind
turbine models and is called WT4FRQ. The model is implemented as a mechanical
wind turbine model in PSS/E, it could however most be seen as an indirect
representation of pitch control and rotor speed control. Δf is measured and the model
changes the active power output reference in the electrical wind model (WT4E2). The
power reference is calculated by the block diagram in Figure 17. The schematic
representation is considered to be enough to investigate the grid code compliance with
regards to the active power control. Two time-lag blocks have been introduced to
better represent actually governance of a wind park. The time constants are set so that
a step response is 3 seconds, in line with [35].
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Figure 17 User written PSS/E model for active power control
8.4 Study cases for active power control
The frequency response is studied by two set of simulations as suggested by National
Grid [OC5.A.4]. The first set deals with active power response capability while the
other set deals with the requirements in Balancing Codes and test possibilities for
islanding operation.
8.4.1 Set 8.1 – Dynamic simulations frequency response capability
This set consists of 27 simulations where frequency response capability is studied. The
available power in the wind is assumed to be 100 %, i.e. the wind turbines have the
possibility to deliver 600MW. The response volume is simulated at different wind
utilization, from P=100% to P=20 % in accordance to the description in [OC5.A.4].
P=100 % 1 2 3 4
P=95% 5 6 7
P=80% 8 9 10 11 12 13 14
P=40% 15 16 17
P=30% 18 19 20 21 22
P=20% 23 25 26 27
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Figure 18 Frequency response volume tests [OC5.A.4.5]
The wind park acted according to grid codes in all simulations. Figure 19 gives one
simulation example; see Fel! Hittar inte referenskälla..3 for more examples.
Simulation 2 & 26 does, as expected, not provide any frequency response. The wind
tubrines in simulation 2 is limited by available power in the wind and wind turbines in
simulation 26 is limited by DMOL.
Figure 19 Active power response, test 18
8.4.2 Set 8.2 – Dynamic simulations, step response and islanding operation
The grid code does also require large power parks to perform another set of simulation
which is called System islanding and step response tests. These simulation do not
simulate an actual islanding operation event, where part of the grid (including the
wind farm) is disconnected from main grid. The simulations indicate, however, if the
wind farm can handle such an event. System islanding and step response simulations
are presented in Figure 20. A simulation setup for islanding operation could be found
in [CP.A.3.6] but not been preformed in this study.
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P=100% BC1 BC2 L
P=100%,
LFSM
BC3 BC4
P=90% A
P=80% D/E F G H I J M
P=80%.
LFSM
N
P=40%
P=30%
P=20% K
BC= Balancing code
* The frequency deviation should bring down the power output from Pmax to DMOL
** These tests are supposed to confirm the sensitivity of the frequency measurement instruments and can therefore not
be performed in these types of simulations.
Figure 20 System islanding and step response tests [OC5.A.4.5]
Test L, M and N is to test the deadband and frequency recording equipment
[OC5.A.4.5]. No representaion of the frequency recording equipment was avalible in
PSS/E and thefore were these simulations not performed. The wind park and the
transmission system behave accordingly to the GB grid code in the performed
simulations. See Fel! Hittar inte referenskälla..3 for more simulation outcome
examples.
9 Reactive power control
Reactive power control is to ensure that the facility can support the voltage. The grid
codes studied in this chapter is listed in Table 9.
Table 9 Articles evaluated with regards to reactive power control
GB Grid Code
with regards to
node A
GB Grid Code
with regards to
node E
ENTSO-E Grid
Code with regards
to node E
CC.6.3, CC.A.7,
CP.A.3.4
CC.6.3.2,
CC.6.3.4
16(3), 20(3)
9.1 Requirements for reactive power control in GB Grid Code
The power park module and the offshore transmission system should be able to
support voltage at the grid entry point. [CC.6.3.1]. It should be possible to inject
reactive power according to Figure 21 during normal operation [CC.6.3.2(c)] which
with regards to voltage level is between 0.95 and 1.05 pu [CC.A.7.2.2].
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Figure 21 Reactive power transfer capability requirements in a P-Q diagram
[C.6.3.2]
The points ABCDE are defined in Table 10
Table 10 Definition of intersection in Figure 21
Point Definition Reactive
power into
grid entry
For 600 MW rated
power (One of two
EAOW branches
A 0.95 p.f. lead -0.33 pu - 197 Mvar
B - 12 % of rated MW -0.12 pu - 72 Mvar
C - 5 % of rated MW -0.05 pu - 30 Mvar
D 5 % of rated MW 0.05 pu 30 Mvar
E 0.95 p.f. lag 0.33 pu 197 Mvar
The reactive power capability requirements are not only a function of active power
delivery but also a function of voltage at the grid entry. Figure 22 shows the V-Q
envelope for reactive power control.
A C D E
MW
Mvar
20 %
50 %
100 %
B
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Figure 22 Voltage – Reactive Power envelop [CC.A.7.2.2]
ABCEFG are defined in the figure as percentage of the nominal voltage level. H & D
are relative and depends on the current limitations within the used equipment
[CC.A.7.2.2].
The reactive power control function should have a set point between 0.95 and 1.05 pu
and slope characteristics between 2 to 7 % [CC.A.7.2.3], which is shown in Figure 23.
Figure 23 Reactive power control requirements [CC.A.7.2.3]
There are also dynamic requirements for reactive power control. The reactive power
output at the onshore grid entry point should commence within 0.2 seconds and 90 %
of the change should be managed within 1 second with a linear response. Oscillations
in reactive power after a required change lower than 5 % of the required change.
[CC.A.7.2.3]. These requirements are visualised in Figure 24.
V
V
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Figure 24 Reactive power response requirements* [36, p.] * This figure is published in Issue 2 of Guide lines for PPM (2008) as an example that would compile with the grid
code. The figure is however not included in Issue 3 (2012) but is estimated to be a good visualisation of the grid codes presented in this chapter.
The reactive power capability of the PPM is also regulated in the grid code. It should
be able to maintain zero transfer of reactive power at the offshore connection point at
the low voltage side of the transformer (node E, Figure 6)[CC.6.3.2(e)]. The ability of
maintaining zero transfer of reactive power is required between voltages of 0.95 and
1.05 pu [CC.6.3.4(a)]. The relationship between PPM requirements at the offshore
connection point and the combined requirements of the PPM and the transmission
system at the onshore grid entry are shown in Figure 25.
0 0.2 1.0 2.0 3.0 4.0 0
0.2
0.4
0.6
0.8
1.0
1 pu Change
1.2 After 2 seconds any oscillations should be less than 5% (peak to peak) of the
steady state change in reactive power at that time.
90% of the required change in Reactive
Capability should occur within 1 second.
Time (Seconds)
0.2s maximum dead time
Reactive Power (pu)
Figure 25 Wind Farm and PPM V-Q envelope
V
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9.2 Requirements for reactive power control in ENTSO-E Grid Code
The pan-European grid code suggested by ENTSO-E for generators does, as
mentioned earlier, only regard requirements at the offshore connection point. The code
requires the ability to maintain zero transfer of reactive power to the offshore
transmission system [Article 20(3)]. This ability should be available within voltage
ranges that is decided by the local TSO [Article 16(3)] but within a maximum range of
0.1 pu [Article 20(3)]. Dynamic requirements for reactive power control, specified in
Article 16(3), becomes irrelevant since Q/P=0. This is in compliance with the current
grid code in GB.
Requirements could, in a later stage, be put on the offshore HVDC-converter station
by ENTSO-E. The code will include requirements for HVDC-links “and potentially
for offshore DC connected Power Park Modules as well” [33]. The responsibility
between the offshore HVDC-converter (OFTO or TSO) and the wind power developer
regarding offshore voltage control is not specified in the grid codes.
9.3 User written models for reactive power control
The GB grid code can be described as a voltage control requirements with a droop and
a maximum limit. The droop can be adjusted in ABB HVDC-light user model AC
control. However, there is no possibility to limit the maximum reactive power transfer,
which is required in the GB grid code. A user model is designed to enable a reactive
power order in compliance with the grid code. Two time blocks are implemented to
enable representation of control devices in the model. The model is implemented as an
exciter at the generator containing the ABB HVDC-light dynamics (i.e CABBO2-
model). The result is implemented at VAR(2) which is used to modulate reactive
power order. The model can be seen in Figure 26 and is more extensive described in
Appendix B.
Figure 26 PSS/E user model for reactive power control
9.4 Study cases for reactive power control
A small slope in the V/Q control diagram (Figure 23) requires the facility to provide
full voltage support at small voltage deviation at the grid entry. This is more
challenging to comply with than providing the full frequency support at larger voltage
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deviations. Consequently, the simulations are concentrated to fulfil grid codes at a
control slope of 2 %.
9.4.1 Set 9.1 – Converter reactive capability in load flow
The purpose of the first load flow calculations is to ensure that the P-Q capability of
the converter (Figure 4) is enough to comply with the grid code without using the
transformer tap changer during static conditions. During this set of load flow
calculations, the active power output is varied from the wind turbines. The voltage at
the grid entry was set to 1.02 pu during the reactive power consumption calculations
and 0.98 pu during the reactive power delivery calculations. The converter output is
then compared to the P-Q diagram provided by ABB (see Figure 4). The 20
simulations are illustrated in Figure 27
Figure 27 Test parameters of Set 9.1
Performance of the onshore converter is shown in Figure 28, where the results also are
compared with the P-Q diagram (Figure 4) provided by ABB. The result is within the
limits of the static capability of the converter station and the converter should thereby
be able to fulfil the static grid code requirements. The tests are presented in more
detail in Fel! Hittar inte referenskälla..4.
MW
V
Mvar
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Figure 28 P-Q diagram that shows the result of tests preformed in 9.1
9.4.2 Set 9.2 – Dynamic performance of onshore converter
Set 9.1 does, however, only evaluate the converter stations requirements to fulfil Grid
Code in a static condition. Set 9.2 studies the dynamic capability of the onshore
converter. The tap-changer is not used during these simulations since the grid code
requires the facility to transfer 90 % of the reactive power within 1 second. The grid
voltage is changed to either 0.98 or 1.02 pu and reactive power order is set to ±
400Mvar (twice the requirement) in order to reach the capability limit of the converter.
This is visualised in Figure 29.
Figure 29 Setup of simulations in set 9.2
A single simulation is presented in Figure 30 and the combined result, presented in
Figure 31.
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Figure 30 Example of a simulation outcome in Set 9.2
Sbase = 600MVA
Figure 31 Results of tests of Set 9.2
The dynamic simulations show that the facility has problem to transfer enough
reactive power into the grid during small voltage drops. Simulation examples and data
for the simulations are presented in Fel! Hittar inte referenskälla..4.
9.4.3 Set 9.3 – Power flow calculations at different active power output and
initial tap settings
One solution for fulfilling the grid codes could be to adjust the tap-changer at the
transformer and thereby adjust the balance between capacitive and inductive
performance of the converter station. This set of simulations repeat the simulations in
Set 9.2, but with different settings on the tap-changer at the transformer.
Reactive power control, dynamic test results
0
0,2
0,4
0,6
0,8
1
1,2
-1 -0,8 -0,6 -0,4 -0,2 0 0,2 0,4 0,6 0,8 1
Q (pu)
P (
pu
)
Test results
Q requirements
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Simulation Transformer winding Voltage at convert bus at
steady state
1-20 1.0125 0.99
21-40 1.0250 0.98
41-60 1.0375 0.97
61-80 1.0500 0.96
The results are presented in Figure 32 and in more detail in Fel! Hittar inte
referenskälla..4.
Figure 32 Dynamic simulation outcome of set 9.3
The result shows that the facility can comply with the grid codes by using the tap-
changer to adjust the balance between capacitive and inductive capacity. Fel! Hittar
inte referenskälla..4 contains data for this set and also the results of the converter
station to consume reactive power from the grid at R=1.0500.
9.5 Potential error in the provided HVDC-model
The model gives a surprising outcome when the turbines deliver 600 MW. The
reactive power output is then formed as a step. The transferred reactive power seems
to reach a maximum limit, as in the other simulations with less active power output.
But, as opposed to other simulations, the first maximum limit is forced after about 0.5
second and the delivered reactive power increases to a new limit. A comparison of the
test for P=570MW and P=600MW is found in
0
0,2
0,4
0,6
0,8
1
1,2
0 0,1 0,2 0,3 0,4 0,5
R1=1.0000
R1=1.0125
R1=1.0250
R1=1.0375
R1=1.0500
Q-Req
P
Q
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Figure 33.
Figure 33 Reactive power output at Pwind=570 MW and Pwind=600 MW
The result indicates that the facility can provide more reactive power during higher
active power transmission. ABB has been asked to comment the result, but no answer
is at this day available. The first limit was assumed to be the maximum limit during
the simulations in Chapter 9. The simulations has also be done with the voltage
control-mode provided by ABB with similar simulation outcome.
10 Faults at the offshore grid and converter trips
10.1 Study cases for the offshore grid and converter stations
Some simulations are done at the offshore grid to investigate behaviour of the wind
park during faults. An extended model was used during these tests to better represent
the offshore grid. One of the two offshore branches was separated into five.
Consequently, the accumulated wind turbine of 300MW was split into five generators,
representing 60MW wind power turbines each. Two of the branches were put on Q-
control and two were put on voltage control. The last branch was put (electrical)
closer to the HVDC-station and the voltage control mode for the turbine were varied
between q-control and voltage-control in different simulations. The model is
visualized in Figure 34. The purpose of the tests is to make sure that the system is
stable and that P, Q and V are within acceptable limits in the event of faults.
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Figure 34 Extension of model during offshore simulations
10.1.1 Set 10.1 – Offshore grid faults
The general test during this set was to add a three-phase fault on a bus and then open
the faulted branch after 140ms. P, Q and V are measured at different busses to ensure
that the system recovers after a fault. The simulations do also investigate differences
between wind turbines in voltage-control and in Q-mode control. The offshore grid
extension is shown in Figure 35 and the simulations setup are shown in
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Table 11.
Figure 35 Offshore grid extension
810 & 812 in V-
control
811 & 813 in Q-
control
814 has low
impedace to HVDC
converter
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Table 11 Parameters for offshore grid faults
Test Bus fault Regulating
mode on wind
turbines at bus
814
Test 1 813 Q-mode
Test 2 813 V-mode
Test 3 612 Q-mode
Test 4 612 V-mode
Test 5 710 Q-mode
Test 6 710 V-mode
Test 7 502 (2nd branch) All turbines in
Q-mode
Test 8 502 (2nd branch) All tubrines in
V-mode
Figure 36 shows an example of the results (i.e. Simulation 5), where the first two
graphs are active power output, the second two graphs is reactive power output and
the last two graphs are bus voltage.
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Converter Sbase = 653Mvar Wind turbine Sbase=60Mvar
Figure 36 Test 5, offshore converter and wind turbine
The simulation outcomes show that the offshore converter can provide voltage support
fast and keep the voltage relative high at the offshore converter. A difference can be
noticed at the power provided to the offshore converter before and after the fault is
cleared. This is due to the decupled wind turbines behind the fault.
In general, very small differences could be seen between having the wind turbines at
bus 814 in Q-mode control or voltage control mode. No reactive power oscillations
between the wind turbines or between the wind turbines and the HVDC-converter
could be seen.
The DC-system part of the transmission is also affected by the offshore grid fault. The
fault causes the DC voltage to drop initially. An oscillation can be observed in the DC
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voltage during and after the fault, which also could be seen in the active power output.
This can be seen in Figure 37.
Figure 37 Outcome of simulation 5, onshore converter and DC system
10.1.2 Set 10.2 - Trip of converter
This set of tests investigates how the system can handle a converter trip. The onshore
converter is tripped in the first simulation and the offshore converter is tripped in the
second simulation.
The trip of onshore converter is mainly handled by the chopper in the HVDC-system.
The maximum DC-voltage is about 1.3 pu before the chopper consumes the active
power from the wind turbines and thereby brings the DC-voltage back to a normal
level. Offshore voltage and frequency remains unaffected by the onshore convert trip
while the chopper is active. When the chopper is unable to continue the active power
consumption, approximate two seconds after the onshore fault, the DC voltage starts
to rise and causes the offshore converter to trip as well. This affects the offshore grid
where the voltage drops and the frequency increases. The wind turbines are not shut
down since the generic wind models not represent any kind of turbine protection. A
more realistic outcome would do an emergency shut down of the wind turbines when
the offshore converter is tripped. The simulation outcome is presented in Figure 38,
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Figure 38 Simulation output, onshore converter trip
The second simulation, an offshore converter trip, gives similar outcome as the last
part of the onshore converter trip. The offshore voltage drops and the frequency rises.
The onshore converter can stay in operation and provide voltage support to the main
grid as a SVC-device.
11 Conclusions
This chapter reflects upon the results presented under chapter 5 to 10.
11.1 Main result
The main result of this study is that the wind park and the HVDC transmission system
will manage to comply with grid codes regarding the investigated areas. The most
critical factor is the ability to provide enough reactive power to the grid during small
voltage dips.
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11.2 Reflection on the grid codes
The GB grid code and the upcoming pan-European grid code are presented within this
report. The European grid code might force smaller changes to the GB grid code, once
in place. This project does however not find any major deviations between the two
codes. The framework could however be interesting to study in order to understand
how the GB grid code might develop in the future. National Grid should develop the
grid code within the ENTSO-E framework which therefore gives hints for a likely
future development.
11.3 Reflection on simulation results
This project indicates that the HVDC-tranmission system handles most of the fault
without affecting the wind turbines offshore. Voltage and frequency deviations at the
onshore grid are not transferred to the offshore grid. This implies that the HVDC-
equipment and characteristics will be the most important part of the facility regarding
grid code compliance. This implies that the wind turbines should be optimized for
operating in a grid with small voltage variations and limited frequency deviations. The
HVDC-transmission system will however need to be designed to comply with the grid
code. This also suggest that the representation of the wind turbines has been less
important of this grid code compliance study and support the use of generic models in
similar studies in the future.
The limiting factor for grid code compliance seems to be the possibility to transfer
enough reactive power to the grid during small voltage dips. This can however be
solved by using the tap-changer to adjust the balance between the ability to produce
and consume power at the grid code. The consequences of a lower initial voltage at the
converter should however be further investigated before this solution is implemented.
The results do also show that it could be beneficial to negotiate the reactive power
control slope with National Grid. A higher slope would ease the requirements of the
HVDC-transmission.
The simulations at the offshore grid indicate the wind turbines and the offshore
converter will manage faults in the offshore grid and converter trips. It is, however,
impossible to draw any conclusions of a suitable control system for the wind turbines.
The offshore converter station seems be the most supporting unit in the system and
wind turbines with both voltage control and reactive power control seems to enable
system stability. No major difference can be seen between the two control strategies.
11.4 Further studies
The GB grid codes are constantly updated and reviewed. Two new revisions have
been realized during this project (November 2012 and January 2013). It is therefore
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important to keep informed about Grid Code development to avoid costly
reengineering of the facility during the construction phase. Once in place, the
European grid code for HVDC-transmission system would be good to investigate.
This study has not focused on the requirements at the offshore grid and these seem to
mainly be regulated with bilateral agreements between the OFTO and the wind power
developer. The offshore HVDC-converter has been the main responsible unit for
voltage regulation and maintaining frequency in the offshore in this study. However,
the wind power couldplay a more prominent role in the voltage regulation if this is
agreed with the OFTO and evaluated to be a better solution.
Power quality could not be studied within this project. This is an important part of the
grid code and a further investigation of this issue is recommended in the future.
Modelling work could also be done with a actual power park controller for frequency
deviations.
The strange results of the reactive power output, presented in 9.5, should be
investigated further. A good representation of the HVDC-transmission system is vital
to perform grid code compliance studies.
The grid code does not only put up minimum requirements. It could be an idea to
investigate if the facility has the opportunity to provide ancillary services to National
Grid. Reactive power control during low or no power generation is a possible service
where the onshore converter station acts as a SVC-device.
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12 References
[1] European Commission. (2010) Energy 2020 - A strategy for competitive,
sustainable and secure energy. COM(2010) 639 final. Brussels.
[2] European Environmental Agency. (2011) Renewable energy production must
grow fast to reach the 2020 target. [Online] Published 2011-08-07, Retrieved 2012-
12-10 from http://www.eea.europa.eu/highlights/renewable-energy-production-must-
grow
[3] Altin, M., Göksu, Ö., Teodorescu, R., Rodriguez, P., Jensen, B.B., & Helle, L.
(2010). Overview of Recent Grid Codes for Wind Power Integration. 12th
International Conference on Optimization of Electrical and Electronic Equipment,
IEEE, p. 1152-1160.
[4] Nelson, R.J., Ma, H. & Goldenbaum, N.M. (2011). Fault Ride-Through
Capabilities of Siemens Full-Converter Wind Turbines. Power and Energy Society
General Meeting, IEEE, p. 1-5.
[5] Tsili, M. & Papathanassiou, S. (2009). A review of grid code technical
requirements for wind farms. IET Renewable Power Generation 3(3) p. 308-332.
[6] Guo, H., Rudion, K. & Styczynski, Z.A. (2011). Integration of Large Offshore
Wind Farms into the Power System. EPU-CRIS International Conference on Science
and Technology, IEEE, p. 1-6.
[7] Bresesti, P., Kling, W.L., Hendriks, R.L. Vailati, R. (2007). HVDC Connection of
Offshore Wind Farms to the Transmission System. IEEE Transactions on Energy
Conversion, 22(1), p. 37-43.
[8] Bahrman, M. P. (2008). HVDC Transmission Overview. Transmission and
Distribution Conference and Exposition, IEEE, p. 1-7.
[9] Xu, L. & Andersen, B.R. (2006). Grid Connection of Large Offshore Wind Farms
Using HVDC. Wind Energy 9(4) p. 371-382.
[10] Gomis-Bellmunt, O., Liang, J., Ekanayake, J. & Jenkins, N. (2011). Voltage–
current characteristics of multiterminal HVDC-VSC for offshore wind farms. Electric
Power Systems Research, 81(2), p. 440-450.
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[11] Arulampalam, A., Ramtharan, G., Caliao, N., Ekanayake J.B. & Jenkins N.
(2008). Simulated Onshore-Fault Ride Through of Offshore Wind Farms Connected
Through VSC HVDC. Wind Engineering 32(2) p. 103-114
[12] Vrionis T.D., Koutiva, X.I., Vovos, N.A. & Giannakopoulos, G.B. (2007).
Control of an HVdc Link Connecting a Wind Farm to the Grid for Fault Ride-Through
Enhancement. IEEE Transactions on Power Systems 22(4) p. 2039-2047.
[13] Department of Energy and Climate Change, GB (2010). National Renewable
Energy Action Plan for the United Kingdom. Article 4 of the Renewable Energy
Directive 2009/28/EC.
[14] Department of Energy and Climate Change, GB (2011). GB Renewable Energy
Roadmap. URN 11D/698.
[15] East Anglia Offshore Wind (2012a). Developing the Zone | East Anglia Offshore
Windfarm Zone | ScottishPower Renewables and Vattenfall. [Online] Retrieved 2012-
11-07 from http://www.eastangliawind.com/developing-the-zone.aspx
[16] East Anglia Offshore Wind (2012b). FAQs | East Anglia Offshore Windfarm
Zone | ScottishPower Renewables and Vattenfall. [Online] Retrieved 2012-11-07 from
http://www.eastangliawind.com/faqs.aspx
[17] Weisbach, H. (2009). Reactive Compensation Study Round 3. Vattenfall Power
Consulting.
[18] Lindström, P.O. & Weisbach, H. (2012). AC Study of East Anglia Offshore Wind
1. Vattenfall Research and Development & Pöyry.
[19] Lindberg E. Owe P. (2012). East Anglia Offshore Wind Farm – 66 kV study for
East Anglia One. Vattenfall Research and Development.
[20] National Grid (2012a). The Grid Code. Issue 5, revision 1.
[21] ENTSO-E (2012a). Network code for requirements for grid connection
applicable to all generators.
[22] National Grid (2012b). Guidance Notes – Power Park Modules. Issue 3. [Online]
Retrieved 2012-10-01 from
https://www.nationalgrid.com/NR/rdonlyres/6C036707-27A4-4C43-AD8A-
777487AAAFFF/56511/GuidanceNotesforPowerParkDevelopersIssue3September201
2.pdf
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[23] ENTSO-E (2012b). Network Code “Requirements for Generators” in view of the
future European electricity system and the Third Package network codes. [Online]
Retrieved 2012-10-05 from
https://www.entsoe.eu/fileadmin/user_upload/_library/consultations/Network_Code_R
fG/120626_-_NC_RfG_in_view_of_the_future_European_electricity_system_and_
the_Third_Package_network_codes.pdf
[24] ENTSO-E (2012c). Network code for requirements for grid connection
applicable to all generators – Frequently Asked Questions. [Online] Retrieved 2012-
10-05 from
https://www.entsoe.eu/fileadmin/user_upload/_library/consultations/Network_Code_R
fG/120626_-_NC_RfG_-_Frequently_Asked_Questions.pdf
[25] ABB (2011). User guide PSSE HVDC Light Open model Version 1.1.11
[26] Gunnarsson, P. (2011). HVDC Converter Operations and Performance, Classic
and VSC. Presentation September 2011, Dahka.
[27] Siemens Power Technologies International (2012). Generic Wind Models.
PSS®E 33.2 Program Application Guide: Volume II.
[28] International Energy Agency (1999). Electricity Market Reform – An IEA
Handbook. IEA Publication, Paris. ISBN 92-64-16187-2
[29] National Grid (2012c). National Grid: Grid Code. [Online] Retrieved 2012-10-25
from http://www.nationalgrid.com/GB/Electricity/Codes/gridcode/
[30] Siemens (2011). Siemens Guide to Wind Farm Grid Code Compliance – Great
Britain. Issue 2.
[31] European Union (2012). Internal Energy Market. Summaries of EU legislation -
Energy. [Online] Retrieved 2012-10-25 from
http://europa.eu/legislation_summaries/energy/internal_energy_market/index_en.htm
[32] Jevnaker, T. (2012). An Electric Mandate - The EU procedure for harmonising
cross-border network codes for electricity. Fridtjof Nansen Institute, FNI-rapport 18.
[33] ENTSO-E (2012d). High Voltage Direct Current - ENTSO-E - European
Network of Transmission System Operators for Electricity. [Online]. Retrieved 2012-
11-01 from https://www.entsoe.eu/major-projects/network-code-development/high-
voltage-direct-current/
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[34] National Grid (2012d). Section K – Technical Design & Operational Criteria &
Performance Requirements for Offshore Transmission Systems v6. System Operator -
Transmission Owner Code. [Online] Retrieved 2012-10-01 from
http://www.nationalgrid.com/NR/rdonlyres/DE34BA62-ACE8-4E88-A038-
0CC138181843/55644/SectionKGoActivev6.pdf
[35] Manwell, J.F., McGowan, J.G. & Rogers, A.L. (2009). Wind Tubrine Contol
Chapter 8 in Wind Energy Explained: Theory, Design and Application, 2nd
edition.
John Wiley & Sons Ltd, Chichester. ISBN 978-0-470-01500-1
Vattenfall Research and Development AB U 12:xx (Internal [S2])
Page A.1 (1)
Appendix A
Data for PSS/E model
5 200
A.1 Branches
From
(bus
nr)
To Voltage
(kV)
Cable
type
Data source R (Ω) X (Ω) C
(µF)
100 200 400 Fictive* - 0 4 0
5 6 320 DC-
cable
(125km)
ABB [25] p.
51
2.3 /
cable
- -
300 501 220 AC
cable
(10km)
Vattenfall
[17], p. 10
0.151 1.31 2.0
601 701 Fictive** Vattenfall
[17], p. 12
0.015 0.04 26.0
*Cable is added to create electrical distance between HVDC converter and
swing bus
** Cable is modulated to represent the offshore collection grid characteristics
100 200
5 6
300 501 601 701 801
502 602 702 802
Vattenfall Research and Development AB U 12:xx (Internal [S2])
Page A.2 (2)
A.2 Transformers
From To Voltage
(kV)
Tap-
change
Data
source
Sbase
(MVA)
X
(pu)*
R (pu)*
200 5 400/416 Yes ABB [25],
p. 50
693 0.14 0
6 300 416/220 Yes ABB [25],
p. 50
693 0.14 0
501 601 220/33 Yes Vattenfall
[17], p. 8
330 0.15 0.005
701 801 33/0.69 No Vattenfall
[17], p. 9
330 0.06 0.0084
pu based on transformer Sbase
A.3 Wind turbines
Load flow:
Sbase= 300MVA.
Dynamics:
Model: WT4E2 & WT4G2
Default parameters, can be found in [27] Chapter 21 page 30
Control mode
Voltage control, bus 701/702
A.4 Swing bus
Load flow:
Sbase = 5000 MVA
Dynamics:
Model: GENCLS
Inertia = 5pu
Damping constant = 0
Vattenfall Research and Development AB U 12:xx (Internal [S2])
Page A.3 (3)
A.5 HVDC-transmission system
Load flow
Active losses (∆P): approximate 3 %, little less at low utilization due to
lower cable losses
Converter at bus 6 acts as swing bus
Dynamics:
Model: CABBO2 (bus 5), cEmpty (bus 6)
Control modes:
Converter at bus 5: DC voltage control, voltage control at bus 200
Converter at bus 6: Passive net operation (i.e active power control),
voltage control at bus 300
Other parameters are set according to ABB and can be found in [25].
PSS/E USER MODEL
Per-Olof Lindström
Pöyry Swedpower AB
ABBQRG
Mvar droop controller for ABB’s CABBO2 model
* Ajusted according to Figure 21 and provided Q in load flow
IBUS ‘USRMDL’ ID ‘ABBQRG’ 4 0 0
6 2 3 T1, R, Qbase, Qmax, Qmin, T2 /
1
R
1
1+sT1
Qbase
1+sT2
Σ
+
-Voltage at
PCC bus
V0
VAR(L+2)
Qmax
Qmin
K K+1
VAR(L)
VAR(L+1)
CABBO2
-1 VAR(2)
Auxiliary
reactive
power order,
for
modulation
(Mvar)
Qpu
STATEs # Description
K Voltage filter
K+1 Regulator block
CONs # Value Description
J 0.05 T1, time constant
J+1 0.02 R, regulator droop
characteristics (pu/pu)
J+2 200 Qbase, VSC reactive power
nominal capacity (Mvar)
J+3 * Qmax, VSC reactive power
max allowed capacity (pu)
J+4 * Qmin, VSC reactive power min
allowed capacity (pu)
J+5 0.05 T2, Regulator time constant (s)
VARs # Description
L Voltage reference
L+1 Verror
L+2 Q-output
Note:
• This model must be used with HVDC
VSC model CABBO2 in constant reactive
power control (ICON(4)=0)
• The model applies droop control of the
Mvar exchange at the PCC bus
• Called as exciter model at filter bus
generator, converter 1
Vpu
Qpu
Qmax
Qmin
Slope 1/R
= load flow operating point
PSS/E USER MODEL
Per-Olof Lindström
Pöyry Swedpower AB
WT4FRQ
Over-frequency droop controller for WT4E2 model
This model is located at system bus #_______ IBUS,
Wind Machine identifier #_______ ID,
This model uses CONs starting with #_______ J,
and STATEs starting with #_______ K,
and VARs starting with #_______ L,
and ICONs starting with #_______ M.
* According to requirements in FSM or LFSM
** According to Pmax=1.0 and Pmin=0.2
IBUS ‘USRMDL’ ID ‘WT4FRQ’ 103 0 1 5 2 2 RBUS, T1, DB, R, dPmin, T2 /
1
R
1
1+sT1
1
1+sT2∆f at
remote busVAR(L+1)
0
Pmin
K K+1
WT4E2
VAR(4)
Power
reference(pu)
dPΣ
P0VAR(L)
-1
DB Pnew
ICON # Value Description
M 200 RBUS, remote bus
CONs # Value Description
J 0.2 T1, time constant
J+1 * DB, frequency positive
deadband (Hz)
J+2 * R, regulator droop
characteristics (pu/pu)
J+3 ** dPmin (pu)
J+4 ** dPmax (pu)
J+5 0.7 T2, regulator time constant (s)
VARs # Description
L Power reference
L+1 Power output
STATEs # Description
K Frequency filter
K+1 Regulator block
Note:
• This model must be used with wind model
WT4E1 orWT4E2
• The model reduces the wind production
when the frequency at the remote bus
exceeds frequency deadband
• Called as mechanical model on wind
machine
• dPmin is a negative value
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Appendix D
D.1 Frequency and voltage variations
D.1.1 Normal operation – Test 1
1.1.1
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D.1.2 Normal operation – Test 2
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D.1.3 Normal operation – Test 3
1.1.2
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D.1.3 Normal operation – Test 4
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D.2 Fault ride through
D.2.1 FRT – 3phase, 0 pu V in 140 ms
The default AC-voltage control mode included in the HVDC-model was used during this test
due to strange reactive power outcomes 0.5 seconds after fault clearance. See two last figures
in D.2.1
1.1.3
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D.2.2 FRT – Line to ground, 140ms
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D.2.3 FRT – 3phase, 0.50 pu V in 710 ms
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D.2.4 FRT – 3phase, 0.85 pu V in 180s
1.1.4
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D.2.4 Fault ride through – 3phase, 0 pu V in 140 ms
Simulation outcome between 0-15s. Pwind is reduced to 70 % between t=10s and t=12s
1.2
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D.3 Frequency control
D.3.1 Frequency control, LF profile (Test 8) D.3.2 Frequency control, 10s HF ramp (Test 10)
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D.3.3 Frequency control, step response (Test F/G) D.3.4 Frequency control, LFSM-mode (Test BC4)
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D.4 Reactive power control
D.4.1 Load flow calculations in set 9.1
Test P wind
( Sbase = 600 MVA)
Grid
voltage
P converter
(Sbase = 653 MVA)
Q converter
(Sbase = 653 MVA)
1 1.0 0.98 0.88 0.26
2 0.95 0.98 0.83 0.25
3 0.90 0.98 0.79 0.25
4 0.80 0.98 0.70 0.23
5 0.70 0.98 0.62 0.21
6 0.60 0.98 0.53 0.20
7 0.50 0.98 0.44 0.19
8 0.40 0.98 0.35 0.18
9 0.30 0.98 0.26 0.17
10 0.20 0.98 0.17 0.17
11 1.00 1.02 0.88 -0.34
12 0.95 1.02 0.83 -0.35
13 0.90 1.02 0.79 -0.36
14 0.80 1.02 0.70 -0.38
15 0.70 1.02 0.62 -0.39
16 0.60 1.02 0.53 -0.40
17 0.50 1.02 0.44 -0.42
18 0.40 1.02 0.35 -0.36
19 0.30 1.02 0.26 -0.31
20 0.20 1.02 0.17 -0.26
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D.4.2 Simulation examples for Set 9.2
1.2.1
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D.4.3 Reactive power provided at different tap-changer settings
1.2.2
Reactive power control, R1=1.000
0
0,2
0,4
0,6
0,8
1
1,2
-1 -0,8 -0,6 -0,4 -0,2 0 0,2 0,4 0,6 0,8 1
Q (pu)
P (p
u)
Test results
Q requirements
Reactive power control, R1=1.005
0
0,2
0,4
0,6
0,8
1
1,2
-1 -0,8 -0,6 -0,4 -0,2 0 0,2 0,4 0,6 0,8 1
Q (pu)
P (p
u)
Test results
Q requirements
Reactive power control, R1=1.000 vs R1=1.005
0
0,2
0,4
0,6
0,8
1
1,2
-1 -0,8 -0,6 -0,4 -0,2 0 0,2 0,4 0,6 0,8 1
Q (pu)
P (p
u)
Test results, R=1.000
Q requirements
Test results, R=1.005
Reactive power control, Diffrent tap settings
0
0,2
0,4
0,6
0,8
1
1,2
0 0,1 0,2 0,3 0,4 0,5
P (pu)
Q (
pu
)
R1=1.0000
R1=1.0125
R1=1.0250
R1=1.0375
R1=1.0500
Q-Req
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D.4.4 Reactive power provided at different tap-changer settings
Q delivered (pu)
Pwind (pu) Tap-changer,
R1=0
Tap-changer,
R1=0.0125
Tap-changer,
R1=0.0250
Tap-changer,
R1=0.0375
Tap-changer,
R1=0.0500
1.00 0.21 0.25 0.28 0.32 0.35
0.95 0.22 0.26 0.30 0.33 0.36
0.90 0.24 0.27 0.31 0.34 0.37
0.80 0.25 0.29 0.33 0.36 0.40
0.70 0.27 0.31 0.35 0.38 0.41
0.60 0.29 0.33 0.36 0.40 0.43
0.50 0.30 0.34 0.38 0.41 0.44
0.40 0.32 0.35 0.39 0.42 0.46
0.30 0.32 0.36 0.40 0.43 0.47
0.20 0.33 0.37 0.40 0.44 0.47
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D.5 Offshore grid faults
Reactive power provided by wind turbines at 814 in the different tests specified in Table 7, Chapter 10
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