UPTEC-ES12026
Examensarbete 30 hp Augusti 2012
Study of Grid Code Compliance
Thanet Wind Farm
Malin Sjölund
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
Study of Grid Code Compliance - Thanet Wind Farm
Malin Sjölund
The trend towards harmonizing grid codes within Europe will increase the demands for grid code compliance. Wind power is for several reasons not comparable to conventional power generation but will, due to large installations, need to show compliance with the grid codes. This thesis is investigating grid code requirements as proposed by National Grid (UK) and ENTSO-E. Modelling work and simulations have also been performed to investigate the grid code compliance of Thanet offshore wind farm in UK. The work has been about investigating frequency response and fault-ride-through criterion and shows that grid codes are fulfilled in Thanet but that the model requires further work.
Popul¨ arvetenskaplig sammanfattning
”Grid Codes” inneb¨ar systemkrav som m˚aste uppfyllas av en produktionsenhet f¨or att den ska f˚a koppla upp sig p˚a eln¨atet. Anledningen ¨ar att eln¨atet ¨ar ett stort och viktigt system som det ¨ar viktigt att uppr¨atth˚alla stabiliteten p˚a. Stabiliteten p˚a eln¨atet kan framf¨orallt k¨anneteckas av att avbrott inte intr¨affar, alternativt intr¨affar ytterst s¨allan.
Men stabilitet inneb¨ar ocks˚a att h˚alla frekvens och sp¨anning inom de nominella v¨arden som ¨ar uppr¨attade f¨or att elektrisk utrustning ska kunna fungera utan sv˚arigheter.
Vindkraft ¨ar historiskt sett en liten energik¨alla och har d¨arf¨or inte varit f¨orem˚al f¨or omfattande systemkrav. Detta utifr˚an att det har resonerats om att vindkraften inte p˚averkat eln¨atet d˚a produktionen varit liten och eln¨atet starkt. Under senare ˚ar har dock vindkraften sett en enorm utveckling och fr˚an att ha inneburit sm˚a maskiner p˚a n˚agra hundra kilowatt byggs nu stora parker som omfattar ett hundratal megawatt.
Det ¨ar av dessa anledningar naturligt att krav p˚a att uppr¨atth˚alla systemet st¨alls ¨aven p˚a vindkraftsparker men det inneb¨ar extra kostnader f¨or de som ¨ager vindkraftparkerna.
Inom EU finns det ambitioner att harmonisera elmarknaden f¨or att underl¨atta handel
¨
over gr¨anserna. Av denna anledning har ocks˚a f¨orfattandet av gemensamma systemkrav p˚ab¨orjats, lett av ENTSO-E (European Network for Transmission System Operators of Electricity).
Det ¨ar tydligt att systemkraven utformas i en riktning s˚a att de kommer bli mer kr¨avande i framtiden, framf¨orallt f¨or vindkraft eftersom denna energik¨alla p˚a m˚anga s¨att skiljer sig fr˚an traditionell. Bland annat ¨ar vindkraften intermittent och har inte det naturliga tr¨oghetsmoment som storskaliga synkronmaskiner besitter.
Existerande systemkrav idag ¨ar utformade utifr˚an systemets behov. England har tradi- tionellt h˚arda systemkrav och kan anv¨andas som en god referens f¨or analys av nya f¨orslag.
England ¨ar dock inte det enda landet som st¨aller krav p˚a vindkraften vid anslutning och turbintillverkare blir tvungna att tillgodose l¨osningar f¨or m˚anga olika behov.
Thanet offshore vindpark har varit i fokus f¨or denna studie, parken best˚ar av vindtur- biner av typen dubbel-matad asynkrongeneratorer. Reglertekniska l¨osningar har legat i fokus vid studier f¨or hur parken uppfyller systemkrav p˚a frekvensrespons och ”fault- ride-through” kriterier d˚a fel simuleras p˚a det ¨overliggande n¨atet.
Studien visar att vindparken ¨ar kapabel att uppfylla de krav som studerats. Studien p˚avisar dock att modellen som anv¨ants har brister och tolkning av resultaten b¨or ta h¨ansyn till detta.
Summary
In terms of wind farm owner Vattenfall is responsible to ensure grid code compliance of its wind farm Thanet. As Thanet is connecting to UK the grid code to comply with is the one issued by National Grid.
The grid codes concerned in this study have been those covering frequency response and fault-ride through. As these disturbances are not convenient to introduce in the real transmission system simulation studies in the software PSS/E have been performed.
The study has been covering modelling work, out of an existing model covering the grid connection, as well as simulation studies regarding dynamics. The modelling work has resulted in an aggregated representation of Thanet wind farm and the transmission grid in the connecting point has been expanded and represented in a Thevenin equivalent.
The model consists of the connection configuration, including SVC Plus devices, and aggregated wind turbines provided by the wind turbine manufacturer. The wind tur- bines also involves a power plant controller, which is a technique developed for future grid code demands.
The simulations assures grid code compliance for Thanet offshore wind farm with re- gards to frequency response and fault ride through for three-pase shortcircuit faults and single-line to ground faults on the overlying network. These simulations are limited to full-load operation.
The study also covers summaries of the grid code issued by National Grid and European Network of Transmission System Operator for Electricity (ENTSO-E). It is concluded that future grid codes most certainly will be more demanding for wind farm owners and that technique such as the power plant controller will be required to achieve compliance.
Abbrevation List
AC Alternating Current
DC Direct Current
DFIG Double-Fed Induction Generator
ENTSO-E European Network of Transmission System Operators for Electricity FRT Fault Ride Through
FSM Frequency Sensitive Mode
HV High Voltage
LFSM Limited Frequency Sensitive Mode LVRT Low Voltage Ride Through
MSC Mechanical Switched Capacitor MSR Mechanical Switched Reactor
NG National Grid
PCC Point of Common Coupling PPC Power Plant Controller
TSO Transmission System Operator WTG Wind Turbine Generator
Contents
1 Introduction 8
1.1 Background . . . 8
1.2 Purpose . . . 9
1.3 Previous Work . . . 9
1.4 Definitions . . . 11
1.5 Limitations . . . 12
1.6 Project Outline . . . 12
2 Theory 13 2.1 Wind power technology . . . 13
2.2 System stability . . . 14
2.2.1 Frequency control . . . 14
2.2.2 Fault Ride Through -FRT . . . 15
2.3 Symmetrical Components and Unbalanced Faults . . . 15
2.4 Power Plant Controller -PPC . . . 18
3 Grid Codes 19 3.1 National Grid . . . 19
3.1.1 Frequency Control . . . 19
3.1.2 Voltage Control . . . 25
3.1.3 Fault Ride Through . . . 27
3.2 ENTSO-E . . . 30
3.2.1 Frequency Control . . . 30
3.2.2 Voltage Control . . . 32
3.2.3 Fault Ride Through . . . 35
5 Frequency Response 45 5.1 High Frequency Events . . . 46 5.2 Low Frequency Events . . . 48
6 Solid Three-Phase Short Circuit Faults 50
6.1 Results from Dynamic Simulation . . . 50 6.2 Voltage and Current Contribution . . . 56 6.3 Swing Bus Behavior . . . 57
7 Unsymmetrical Single Line to Ground Fault 60
7.1 Zero sequence data . . . 60 7.2 Voltage and Current Contributions . . . 61 7.3 Dynamic Simulation . . . 63
8 Discussion 67
8.1 Grid Codes . . . 67 8.2 Thanet Simulation Model . . . 68 8.3 Conclusion and Prospects for Further Work . . . 71
1. Introduction
1.1 Background
Grid codes are basically the rules to be followed when connecting generators to the grid.
The grid codes within a transmission region are issued by the, for that region, transmis- son system operator (TSO), with the purpose to ensure system stability. As wind power until the end of the nineties was rather small and had small impact on system operation, grid code requirements specially issued for wind power plants are a fairly new concern [1].
With wind power plants growing bigger in size it is reasonable that wind power must be included in the grid codes. Wind power is an intermittent power source by nature though and can therefore not be regarded as a conventional synchronous generation unit.
The region for which the Transmission System Operator (TSO) is responsible is nor- mally a country (or part of a country for countries of a greater area). Since the purpose with the grid codes is to sustain system stability, the grid codes will depend on system needs. The grid codes contain power quality requirements as well as system stability requirements, this work will be covering system stability, i.e. frequency response, voltage stability and fault ride through (FRT).
At present the grid codes issued by the European TSO:s are individual for the coun- tries. Vattenfall is operating wind power in Germany, UK and Holland as well as in Sweden and is thereby facing different grid codes for the different countries. The grid codes in UK have shown to be technically demanding and are therefore extra cost driving.
The European Network of Transmission System Operators of Electricity (ENTSO-E) has been working for a common grid code for the TSO:s operating in Europe. This grid
1.2 Purpose
This thesis has the main purpose to study grid code compliance for Thanet wind farm UK. Secondly it serves to clarify how different grid codes affect technical solutions and their costs. Theory will be complemented with simulation studies to give a systems perspective and a better understandning for techniques involved in meeting grid code demands.
For several reasons wind power is not comparable to conventional, large-scale syn- chronous generation. Also, the fact that demands from grid codes differ between coun- tries put preassure on the technique developers to deliver several solutions. In order to obtain economies of scale and create a more harmonized market ENTSO-E serves its purpose.
However this thesis holds a wind power point of view and will therefore discuss the studied grid codes out of this perspective. The objective is to highlight which future demands will force extra costs to wind power installations and to give a ground for dis- cussion whether it is reasonable demands or what changes could be proposed.
The simulations will be dynamic studies on the offshore windfarm Thanet connected indirectly to the transmission grid operated by National Grid in UK. The purpose is to study how trip of generation and short-circuits on the overlying net will affect frequency and voltage stability and their control techniques. The goal is to use the model and simulations for verification of grid code compliance with National Grid (NG) [2].
1.3 Previous Work
Thanet is an offshore windfarm outside of UK. It has a rated power output of 300 MW and consists of 100 wind turbines, each rated 3 MW, an aggregated representation is shown in figure 1.1.
The Thanet wind farm model origins from Siemens PTI and has been updated due to new model releases and the need for implementation of new control techniques.
A simplified model of the connection point, consisting of an accumulated generation of 30 MW connected to the overlying net represented as a swing bus, has already been studied by Vattenfall VRD. The study covering this model so far focuses on load rejec- tion [4].
When there is a mismatch between generation and load the frequency will alter, e.g.
when there is a trip of load (load reduction) the system frequency will increase. The TSO in UK, National Grid (NG), allows an increase of frequency up to 52 Hz, whereby the study has been carried out by stepwise reducing the load until this maximum frequency
is reached. The study shows that the maximum frequency is reached by a mismatch of 30 % of the wind power park generation.
The study implies imperfection in the model, since some variables have ”suspected initial conditions” according to the software PSS/E. This implies not only imperfection in the model but also a need for further understandning of the model and how it should be operated.
1.4 Definitions
As can be seen in figure 1.1 the entire windfarm consist of four radials connecting to two three-windning tranformers (located on the offshore platform) which are connected to the point of common coupling (PCC) via two seacables. SVC Plus devices are connected onshore directly to the PCC. The overlying grid is at the PCC represented by a swing bus modelled by a Thevenin equivalent.
Because of the system being divided into several subsystems it is of importance to claify these definitions:
• Wind farm will hereafter refer to the entire wind farm system connected to the PCC, i.e. SVC Plus, seacables and the internal grid connecting the wind turbines.
• Offshore Platform will refer to the platform where three-winding transformers are located. For this reason, when discussing the ”low-voltage side of the offshore platform” this will mean the 33 kV side of the three-winding transformers.
• Wind turbine aggregate will be one wind turbine scaled up in order to represent several turbines. If not stated differently the aggregates will be discussed from the low-voltage side of the step-up transformers.
• Seacable are the cables conecting the offshore platforms to the PCC. The seacable system does not contain the SVC Plus which are subsystems on their own con- nected to the PCC. The length and impedances of the seacables are calculated and modeled by Siemens PTI in the original model.
• SVC Plus consist of STATCOM, MSC and MSR devices, the rating of the STAT- COM is +25/-22 MVAr and has been delivered by Siemens. In PSS/E each STAT- COM is modeled as the standard library model CSTCNT.
• Overlying grid will refer to the grid at which the PCC is the entrance point. The overlying grid has been modified during the simulations but is at all times repre- sented by a swing bus represented as a Thevenin equivalent. What modifications have been done to the grid and in which purpose is explained for the different simulation cases.
• System refers to the entire system, i.e. wind farm and overlying grid.
1.5 Limitations
The grid code documents are covering a wide range of rules for generating units to com- ply with. The aim of this thesis is to study the system stability and will only analyze the grid codes’ demands on frequency response, voltage control and fault ride through (FRT).
Due to lack of dynamic data the overlying net is represented by a swing bus with short circuit power as calculated from its Thevenin equivalent. Other units are represented as loads, since loads do not require any dynamic data. Other equipment at the over- lying grid, i.e. cables and tranformers, are given typical data rather than the site specific.
For offshore power parks the grid code offers a choice of fulfilling the grid code at the PCC or at the low voltage side of the offshore platform. Due to the wind farm config- uration this thesis has been focusing on fulfilling grid codes at PCC level and does not present resluts for the offshore platform.
The wind farm configuration has offered restrictions in how the control devices could be implemented in PSS/E.
The wind turbines’ response can be assumed different dependning on at which load they are operating. This thesis has only covered full-load operation.
1.6 Project Outline
As the grid codes are a main part of this project these have been studied in detail.
The grid codes developed by National Grid (UK) are of concern regarding whether the plant will reach grid code compliance or not and these form the base from which the simulations are performed. The grid codes proposed by ENTSO-E will be treated as a lit- erature study and serve as reference for the discussion regarding results and future work.
When the requirements are identified modelling work will continue and focus on Thanet.
A Power Plant Controller (PPC) is identified as a need to fullfill the Brittish grid code and will therefore be implemented in the model. Effort will also be put on modelling of the overlying net in the connection point, as requirements on withstandning faults apply for faults at a voltage level of 275 kV or above.
2. Theory
Over a few decades the development of wind power has been subjected to a journey from individual turbines rated at kW level to wind farms rating some hundred MW.
As long as wind power contributed to the power system as small generating units the common practice was connection directly to the distribution grid and disconnection in presence of disturbances. This worked well since the wind power generation was small and the grids could be assumed fairly strong. With an increased integration of wind power, consisting of considerably larger units, the modern wind turbines are required to and therefore designed to fulfill increasingly demanding grid codes [6].
2.1 Wind power technology
From an electrical point of view wind turbines can be divided into two groups; fixed- speed and variable-speed operation. The wind power generators used at Thanet are of the type Double-Fed Induction Generators (DFIG). This is an induction generator using a cascade coupling in order to obtain a so called narrow variable speed intervall.
Having a variable speed intervall improves the mechanical effiency of the machine and also reduces the mechanical stresses that come from wind variations [5].
The DFIG consists of a wound induction generator with its stator directly coupled to the grid. The rotor is interfaced through a partially rated variable frequency converter.
One reason for the popularity of DFIG is that its design only requires the converter to handle about 30 % of full power. Compared to full variable-speed interval generators, that requires full-rated converters, this has benefits both for size and economical matters [5].
DFIG design works in two operating modes, sub-synchronous and super-synchronous.
The sub-synchronous operating mode refers to a partial load situation and in this case power is supplied from the wind turbine to the grid via the stator, whilst a converter is used to supply the rotor with slip-power when needed. In super-synchronous mode a nominal load range is accounted for. In this case power produced by the wind turbine is supplied to the grid not only by the stator but also extra slip power is provided by the converter, this accounts for about 25 % of rated power [7].
Figure 2.1: Electrical priciple of a Doubly-Fed Induction Generator
2.2 System stability
In order to obtain a stable system and a secure electricity supply, network frequency and voltage levels must be kept close to nominal. In case of disturbing events, control mechanisms must act in order to counteract possible deviations. Grid codes, typically developed by the transmission system operator (TSO), facilitate rules for grid connection, fitted to system needs [1].
2.2.1 Frequency control
Frequency is coupled to active power and units can thus regulate their active power output in order to meet system needs for frequency compensation. Unlike conventional power generation, with large units that responds to frequency deviations with a natural inertia, DFIG:s require a programable control providing a synthetic inertia since the rotor is decoupled from the grid.
Frequency response service is an automatic response, which is carried out in the power governor, which measures the system frequency and changes the active power output from the power plant based on configurable settings. Increasing the power output when frequency is low and vice versa makes it possible for the wind power plant to contribute
2.2.2 Fault Ride Through -FRT
Fault Ride Through (FRT) or Low Voltage Ride Through (LVRT) criterion applies to the wind farms capability to withstand a voltage dip that follows faults on the overlying net. The purpose is to avoid cascade effects during faults, but demands are also covering the need for the wind farm to contribute towards system stability after fault clearance.
Managing LVRT is difficult for DFIG:s and until recently the common practice was to disconnect the generator in order to protect the vulnerable rotor-side converter [9].
This difficulty derives from that stator flux cannot follow a sudden voltage dip, and a DC component appears. The rotor keeps rotating and a high slip occurs, this tends to cause overvoltage and overcurrent in the rotor circuit due to the effect of DC voltage accelerating electrons. [10]
Technically this is avoided by adding a chopper to the DC-link. The chopper will protect the converter and ensure that current and voltage limits will not be exceeded.
Some manufacturers are also adding a crowbar to the DFIG rotor circuit. During a voltage sag the crowbar will short-circuit the rotor. Basically this turns the DFIG to a regular induction generator and separates the converter from the DFIG [7]. This tech- nique is not used at Thanet though.
Roughly estimated the FRT criterion increases the investment cost for wind power with about 5 % [8].
Figure 2.2: Electrical principle of adding a crowbar and chopper to achieve FRT [7]
2.3 Symmetrical Components and Unbalanced Faults
To express unsymmeric combinations of three phases a system to replace the three phase-components with three symmetrical components is derived [13]:
• The positive sequence is a sequency with three components with the same magni- tude but with a displacement of 120◦ and 240◦, respectively. The phase sequence is abca.
• The negative sequence also consist of three components with the same magnitude.
In the negative sequence they have the displacement of 240◦and 120◦, respectively and the phase sequence is acba.
• The zero sequence is a sequence of three components that have all the same mag- nitude and phase.
The three symmetrical components are commonly denoted with 1 (for the positive se- quence), 2 (for the negative sequence) and 0 (for the zero sequence) and the relationship between symmetrical components and the three phase system yields as follows:
IA= I1+ I2+ I0 IB = a2I1+ aI2+ I0 IC = aI1+ a2I2+ I0 and
I1 = 13(IA+ aIB+ a2IC) I2 = 13(IA+ a2IB+ aIC) I0 = 13(IA+ IB+ IC)
with a = ej120◦ representing the phase displacement. Figure 2.3 shows an example of an unbalanced situation and how it can be expressed in its symmetrical components.
The reason for the derivation of symmetrical components is for the assesment of unbal- anced fault analysis. The most common type of fault is the single-line to ground fault.
When doing fault analysis a no-load situation is assumed, which will yield network rep- resentation as shown in figure 2.4
Figure 2.4: Sequence network for single line to ground fault [14]
Analysing figure 2.4 leads to the following sequence currents:
I1 = I2 = I0 = Z E1
0+Z1+Z2+3ZF
when translating this back to phase currents the following is valid:
IA= 3I0= Z0+Z1E+ZA2+3Z IB = IC = 0 F
For a solid short circuit on the faulted line, i.e. with ZF = 0 and Z1 = Z2 the voltages will be given as:
UA= 0 UB = E1√
3� −150◦
UC = E1√ 3� 150◦
which shows that the highest obtainable voltage is the line-to-line voltage [14].
The zero sequence current can only flow in parts of the circuit that have a fourth conduc- tor (that serves as a return path). For this reason delta and undgrounded wye portions of the system will not allow the zero sequence current to flow [15]. Thanet wind turbines are connected with wye-delta transformers, which (for mentioned reasons) will not allow any zero sequence current during fault occations.
Figure 2.5: Delta -Wye transformer zero-sequence current behavior [15]
2.4 Power Plant Controller -PPC
A power plant controller is a programmable control developed by the wind turbine man- ufacturer. It serves the purpose of controlling reactive power and voltage at power plant level instead of letting every turbine individually respond to disturbances. It also gives the Double-Fed Induction Generators (DFIG) a synthetic inertia, which gives the tur- bines a more synchronous behaviour responding to frequency deviations.
Depending on grid code, there might be demands on MSC:s or STATCOM:s to sup- port reactive power flow and voltage control. The manufacturer provides a solution for the PPC to control also these devices.
At Thanet the PPC will have an important role in controlling the frequency. Reac- tive power control is however controlled by the SVC Plus devices that will be closing the control loop and dispatch control signals to the PPC.
3. Grid Codes
The grid codes that are of interest for this study are the grid codes issued by National Grid (UK) and ENTSO-E (EU) . Further this study is focusing on the parts of the grid codes covering frequency and voltage regulation due to active and reactive power control respectively.
3.1 National Grid
The following grid code requirements are those defined for offshore power parks rated above 50 MW [2].
3.1.1 Frequency Control
The nominal frequency within the National Electricity Transmission System is 50 Hz and frequency shall be kept within 49.5 - 50.5 Hz. Exceptional circumstances allows frequency to deviate between 47 - 52 Hz and generating units must then be operated according to the pre-defined time limits listed in table 3.1.
Frequency Requirement
47 - 47.5 Hz Operation for at least 20 seconds 47.5 - 49 Hz Operation for at least 90 minutes 49 - 51 Hz Continuous operation required 51 - 51.5 Hz Operation for at least 90 minutes 51.5 - 52 Hz Operation for at least 15 minutes
Table 3.1: Frequency National Grid
Disconnection within the frequency range 47.5 - 51.5 Hz is first allowed after agreement with National Grid. If frequency excursions would occur outside of the specified range, i.e. above 52 Hz or below 47 Hz, the generating unit owner is responsible for protection of its units against damage.
All generating units are required to facilitate a frequency control based on active power output modulation. This control type is referred to as frequency sensitive mode (FSM)
and is characterized by settings of deadband and slope. The slope must be within 3 - 5
% and the deadband must not be greater than±0.015 Hz. The frequency control device might be installed on the power park module, each power park unit or in a combination of both.
Frequency sensitive mode (FSM) is initiated by National Grid (NG) and requires the wind power park to respond to frequency changes within the range 49.5-50.5 Hz with a primary, secondary and high frequency response characterized in figure 3.3 and 3.4.
When FSM is not initiated the plant shall operate in Limited Frequency Sensitive Mode (LFSM), which does not require primary, secondary or high frequency control, the tech- nique for FSM must still be possible though.
If the frequency deviates with more than +0.5 Hz when the plant is operating in FSM or with more than +0.4 Hz when operated in LFSM, the plant i required to decrease its power output with at least 2 % /0.1 Hz. The characteristics covering FSM are illustrated in figure 3.1 and LFSM in figure 3.2.
By these means frequency response has two meanings. Primary response and high fre- quency response is defined as the response adressed whithin 10 seconds after a frequency deviation. The response must be accordning to the slope of 3-5 % and the magnitude shall be according to figure 3.5. For large frequency deviations, i.e. +0.5 Hz the response is required in terms of 2 % power reduction per 0.1 Hz.
Figure 3.1: FSM characteristics in different frequency ranges [2]
Figure 3.2: LFSM characteristics for different frequency ranges [2]
Primary, secondary and high frequency response are defined according to their response times. Primary and high frequency response are refering to the immediate response that follows a frequency deviation up to± 0.5 Hz. Secondary response is following a primary response and is referring to the time intervall 30 seconds - 3 minutes after a frequency deviation, see figure 3.3 and 3.4.
Figure 3.3: Frequency response requirements for primary (P) and secondary (S) fre- quency response [2]
Figure 3.4: Frequency response requirements for high (H) frequency response [2]
Frequency response requires a plant operating range which ranges between maximum capacity, i.e. 100 %, and minimum capacity, which can not be higher than 65 % of rated capacity. Further a designed minimum operating level is defined, which can not be more than 55 % of rated capacity, see figure 3.5.
Figure 3.5: The minimum frequency response respresented as the inner curve, whilst a typical response for a power plant is shown as the outer curve. The typical frequency response is based on a droop of 3.33 % [16].
Due to increase in system frequency the power plant should be able adjust down to de- signed minimum operating level and when the system frequency has recovered to target the power plant shall recover to minimum capacity. The designed minimum operating level is the output at which the power park module has no high frequency response ca- pability. Therefore the power park module is not obliged to go below this output unless the frequency goes above 50.5 Hz.
Frequency response (primary, secondary and high) verification is required at six MW loading points:
3.1.2 Voltage Control
The transmission grid is characterized by 3 different operation voltages with their normal operation ranges as stated in table 3.2 below.
Nominal Voltage Normal Operation Range
400 kV 0.95 - 1.05 p.u.
275 kV 0.9 - 1.1 p.u.
132 kV 0.9 - 1.1 p.u.
Table 3.2: Voltage ranges National Grid
For 400 kV a range of 0.9 - 1.1 p.u. can be allowed when special conditions prevail but voltage above 5 % of nominal will last no longer than 15 minutes if not abnormal conditions prevail. System voltages below 132 kV will remain within ±6 % of nominal.
At grid entry point the active power output shall not be affected by voltage change within the normal operation range, other than change in losses due to increased and decreased voltage. Also the reactive power output under steady state conditions shall be fully available within the voltage range 0.95 - 1.05 p.u.
The steady state tolerance of reactive power transfer to and from the offshore trans- mission system must not exceed 5 % of rated MW, if not agreed differently in the Bilateral Agreement.
Each offshore unit rated above 50 MW must be capable of contributing towards voltage control through continuous changes to the reactive power supplied to the National Elec- tricity Transmission System.
Figure 3.6 describes the operation range at which the power plant must be cabable of supplying reactive power for voltage control to the grid.
Figure 3.6: P-Q chart at the grid entry point [2]
• A is the point for power factor 0.95 leading at rated power, i.e. corresponds to -0.33 p.u. reactive power. The grid code requires this reactive power capability down to 50 % of rated active power output.
• B is the point for power factor 0.95 lagging, i.e. 0.33 p.u. reactive power produc- tion. The grid code requires a capability of this reactive power down to 20 % of rated active power output.
• C is equivalent (expressed in MVAr) to -5 % of rated MW, i.e. -0.05 p.u. reactive power
• D is equivalent (expressed in MVAr) to 5 % of rated MW, i.e. 0.05 p.u. reactive power.
• E is equivalent (expressed in MVAr) to -12 % of rated MW, i.e. -0.12 p.u. reactive
Figure 3.7: Operational envelope describing voltage regulation at Grid Entry Point [2]
For an on-load step change the control system must respond so that reactive power output shall commence within 0.2 seconds from that the application of step-change was applied. The response shall be so that 90 % of full reactive capacity will be produced within 1 second see figure 3.8. The reactive power response shall vary linearly with the magnitude of step change and setting time shall be maximum 2 seconds (with a peak- to-peak magnitude of less than 5 % of change in steady state reactive power).
The response of the voltage control system shall be demonstrated by applying suitable step disturbances. The damping of the control system shall be judged to be adequate if corresponding active power response to the disturbances decays within 2 seconds of the application of the step.
3.1.3 Fault Ride Through
Then fault clearance time shall be stated in the Bilateral Agreement. The agreed fault clearance time will be the slowest allowed fault clerance time and shall not be stated faster than:
• 80 ms at 400 kV
• 100 ms at 275 kV
• 120 ms at 132 kV
Figure 3.8: Response required for an on-load step change [16].
Nothing says that the actual fault clearance time cannot be faster but the probability that fault clearance times exceed the agreed must not be greater than 2 %.
The operator of an offshore generation plant can chose either to meet fault ride through criterions on the interface point with the onshore grid or on the low voltage (LV) side of the offshore platform.
If fault ride through is considered for the PPC, the following is valid:
• The power park module must remain transiently stable and connected to the sys- tem, without tripping of any generating unit, for at least 140 ms for any voltage dip (balanced or unbalanced) down to 0 p.u. (at the fault location). The actual duration of zero voltage will be dependent on local protection arrangements and circuit breakers operating times.
proportion to retained voltage. But exception is made due to the intermittent nature of wind power, taking restraints in possible power generation into account (if the changes occur in the time range of the voltage dip and restoration).
• The power park module shall provide maximum reactive current output during the dip without exceeding transient rating limits.
When voltage dips occur for duration greater than 140 ms the offshore power park mod- ule shall remain transiently stable when the voltage dip is balanced. Here, as well, the recovered active power output is expected to be proportional to the voltage restoration.
In this case the active power shall be restored to at least 90 % of the pre-disturbed value within 1 second of the restoration of voltage (back to at least 0.9 p.u.) . Though, here as well are exceptions made for the intermittent nature of wind power.
Figure 3.9 illustrate the meaning of the voltage duration profie for voltage dips with durations lasting longer than 140 ms. The graph does not illustrate voltage recovery but for how long, at each voltage level, the wind farm needs to stay connected without tripping.
Figure 3.9: The principle of the voltage-duration profile for voltage dips lasting longer than 140ms [2].
Figure 3.9 contains the following important retained voltage levels and their associated minimum time durtion for which the power park needs to stay connected:
• 30 % retained voltage -384 ms
• 50 % retained voltage -710 ms
• 85 % retained voltage -3 minutes
Following conditions prevail for wind power and other non-synchrous units:
• If the wind farm is only operating at less than 5 % or (due to high wind speeds) more than 50 % of the turbines are set out of service, the requirements stated above do not apply.
• The non-synchronous generators must withstand the negative phase sequence load- ing, incurred by clearance of close-up phase-to-phase fault.
3.2 ENTSO-E
The grid code developed by European Network of Transmission System Operators for Electricity (ENTSO-E) [3] serves the purpose to guard cross-border network issues. More concrete the targets to be fullfilled with the grid code is:
• To support the competition and functioning of the internal market of electricity and crossborder trade.
• To facilitate targets for penetration of renewable generation
• To maintain security of supply
Because of the code only serving cross-border issues the code is at some points referring to national frameworks, which means the grid code issued by National Grid. Otherwise the categorization that applies to Thanet will be ”Offshore Power Park Modules”. Fur- ther the ENTSO-E grid code chategorizes offshore power parks dependning on whether connected with AC, DC or hybrid and also depending on whether the connection is seen in a single onshore connecting point or as a meshed network. The following summary is regardning an AC connection in a single onshore point as this is the case for Thanet.
3.2.1 Frequency Control
To secure system stability generating units must stay connected and in operation at least
Frequency Requirement
47 - 47.5 Hz Operation for at least 20 seconds 47.5 - 48.5 Hz Operation for at least 90 minutes 48.5 - 49 Hz To be decided by each TSO but not
less than 90 minutes
49 - 51 Hz Continuous operation required 51 - 51.5 Hz Operation for at least 90 minutes 51.5 - 52 Hz Operation for at least 15 minutes
Table 3.3: Operation requirements with regard to frequency ranges (ENTSO-E) The grid code requires operation in limited frequency sensitive mode (LFSM) and fre- quency sensitive mode (FSM).
LFSM is required as a response for both over- and underfrequencies and shall be ac- tivated between and including 50.2-50.5 Hz and 49.5-49.8 Hz. A droop shall be applied in the range 2-12 %. Actual frequency threshold and droop are decided by relevant TSO.
For natural reasons the limit to which the power plant module will be able to respond to underfrequencies will be its maximum capacity.
FSM will be characterized as in figure 3.10, with settings in the ranges listed below.
Actual settings will be issued by the relevant TSO.
Parameters Ranges
Active Power range related to Maximum Capacity |∆PP 1|
max 2-10 % Frequency Response Insensitivity |∆fı| 10-30 mHz
|∆fı|
fn 0.02-0.06 %
Frequency Response Deadband 0-500 mHz
Droop s1 2-20 %
Table 3.4: FSM ENTSO-E
Figure 3.10: Frequency Sensitive Mode Characteristics [3]
In case of overfrequency the active power frequency response is limited by the power park modules minimum regulating level and in case of underfrequency it is limited by the modules maximum capacity.
A time delay for activation of frequency response is accepted but must not exceed 2 seconds. The total response shall have responded within 30 seconds.
3.2.2 Voltage Control
To secure stable operation the offshore power park module has to operate within voltage range of 0.9 pu - 1.05 pu without disconnecting. If the voltage exceeds 1.05 pu but not 1.10 pu operation must proceed for at least 15 minutes.
Nominal Voltage Normal Operation Range
equal to or less than 10 %. This voltage control shall ensure a reactive current at the low voltage terminals of the step-up transformer with a contribution with at least 2 % of the rated current per percent of voltage deviation, see figure 3.11. The reactive current injection shall be achieved within 40 ms after fault detection. The relevant TSO will decide the actual setting regarding this fast acting reactive current injection and also possess the right to decide if requirements regarding assymmetical current injection is necessary in case of assymetrical faults.
Figure 3.11: Principle of voltage support by fast reactive current injection [3]
With regard to reactive power capability it is for the relevant network operator to decide an appropriate U-Q/Pmax profile. Referring to figure 3.12 in the grid code the profile shall not exceed the inner envelope, there is no need for the profile to be rectangular though. Further the U-Q/Pmax profile cannot be positioned outside the outer envelope also referring to figure 3.12.
Figure 3.12: U-Q/Pmax profile for an offshore power park module [3]
The maximum range of Q/Pmax in Great Britain shall be 0.66 and maximum range of steady state voltage level 0.1 pu. For profile shapes other than rectangular (compare figure 3.7), the voltage range represents the highest and lowest values.
The reactive power provision capability requirement applies at the high-voltage ter- minals of the last step-up transformer to the voltage level at the connection point.
The P-Q chart in figure 3.13 describes the requirements of reactive power capability when the power park module is operating at active power outputs below maximum ca- pacity. The power park module shall be able to operate in every point not exceeding the outer envelope, if all generating units are in service, it shall also be capable of providing reactive power at any operating point inside the inner envelope also seen in figure 3.13.
Regarding reactive power control the network operator in coordination with relevant TSO are to decide whether reactive power shall be provided by voltage control, reactive power control, power factor control or by a combination of two of these.
• In case of reactive power control mode the power park module shall be able of setting the reactive power target anywhere in the reactive power range. Setting steps shall be no greater than 5 MVAr or 5 % of full reactive power (the smallest value).
• In case of power factor control mode the target power factor as well as the tolerance in the connection point will be decided by relevant network operator. The power park module shall control the power factor within the reactive power range with steps no greater than 0.01 (power factor).
Figure 3.13: P-Q profile for an offshore power park module [3]
3.2.3 Fault Ride Through
The relevant TSO shall define a voltage against time profile at the connection point.
This voltage against time profile shall be expressed by a lower limit, which is the voltage level at the phase experiencing the lowest retained voltage (regardless the voltage level at the other phases). This profile shall be expressed as a line within the limits composed by the red lines in figure 3.14.
Figure 3.14: The Fault Ride Through profile shall be expressed as a line at or between the red lines defining the shaded area [3]
The relevant TSO as well as the relevant network operator shall define pre-fault and post-fault parameters for the fault ride through capability:
• Pre-fault minimum short circuit capability at the connection point (expressed in MVA)
• Pre-fault operating point expressed in active power and reactive power output in the connection point
• Pre-fault voltage at the connection point
• Post-fault minimum short circuit capacity in the connection point (expressed in MVA)
4. Model Work
4.1 Aggregating Thanet wind farm
Aggregating units with the same dynamic properties is a well-established method in power system analysis and has proven efficient. It roughly means scaling up one wind turbine to make it represent several units [12].
The power plant controller (PPC) is designed in order to control the wind farm due to measured power flows in the point of common coupling (PCC). In the way the PPC is constructed for PSS/E it is not meant to handle several individual wind turbines but requires the production to be aggregated into a few big generating units.
A wind farm network was provided by Siemens PTI for the PSS/E version 30. This model has been updated to the later PSS/E version 32 at Vattenfall. The windfarm consists of two identical radials whereof each radial consists of two radials with the pro- duction of 90 MW and 60 MW respectively, i.e. 150 MW in each radial summing up to the total 300 MW when both radials are considered.
For the active power production the turbines individual production is purely additive.
The turbines’ reactive power production is also additive but in this case also the cable configuration and the impedance have a significant contribution to the reactive power flow. Therefore, the impedance must be considered when balancing the aggregation.
The aggregated wind farm looks as in figure 4.1.
The turbines were scaled up due to the following initial values, based on one turbine:
Active Power Reactive Power Base Power
3.0 MW 0.178 MVAr 3.14 MVA
Table 4.1: Rated power per wind turbine
Aggregation of the impedance was done roughly. Since the current flowing in the network is not enclosed in a loop but rather adding up, Kirchoffs law applying to adding all impedances into one equivalent is not valid. Instead the cable impedance was applied as
a proportion of cable resistance, as the losses were known and cable data was provided [20]. Impedance in transformers was applied as empirically verified, typical values rather than site specific.
r’ (Ohm/km) x’ (Ohm/km) c’ nF/km
0.095 0.102 290
Table 4.2: Cable data for the internal network
As the grid code requires a zero transfer of reactive power in the PCC the aggregation of reactive power was further modified to fullfill this criterion in load flow, this resulted in two types of aggregates with the following production levels:
Active Power1 Reactive Power1 Base Power1
90 MW 7.05 MVAr 94.2 MVA
Active Power2 Reactive Power2 Base Power2
60 MW 4.7 MVAr 62.8 MVA
Table 4.3: Wind turbine aggregate production in load flow
The grid code requires a reactive power range from power factor 0.95 inductive to 0.95 capacitive, i.e. ±49.3 MVAr per sea cable:
* Q = Prated∗ tan(arccos(0.95))
In order to meet grid code requirements, in PCC, regarding reactive power capabil- ity the wind farm is equipped with Static Var Compensator Plus (SVC Plus) devices, one per each export cable. The entire SVC Plus block consist of a step-up transformer, a MSC, a MSR and a SVC Plus converter (STATCOM). The SVC Plus converter is rated +25/-22 MVAr at rated terminal voltage and the MSC and MSR 38 MVAr each.
The SVC Plus converter is modeled as the PSS/E standard library model CSTCNT and MSC and MSR as static shunts [19], [20].
4.2 Study of the overlying net
Figure 4.1: Network diagram showing the aggregated Thanet wind farm.
Figure 4.2: Large production units close to Thanet grid connection [17].
Figure 4.3 is describing the location of Thanet wind farm connection to the British grid.
It can be seen that it is connected to the 132 kV bus known as Richborough. Its closest connection to the 400 kV grid is in Canterbury North. The grid is represented with a swing bus calculated as a Thevenin equivalent at the RICH11-node. At 132 kV this is rated 3406 MVA [21]. Calculating the short circuit ratio (SCR) from the relationship:
SCR = PSSC
W F
With SSC = 3406M V A being the short circuit power in the connecting bus and PW Frated = 300M W being the rated power from the wind farm, this yields a short circuit ratio above 10, which justifies the assumption of a strong grid. However to understand the stiffness
Figure 4.3: Geographical location and connection conditions for Thanet wind farm [18].
4.2.1 Model for frequency response
As there is a lack of dynamic data regarding other generating units connected to National Grid, the best option is to model Dungeness as a negative load. This can be seen in figure 4.4, in the network diagram blue is indicating a voltage level of 400 kV, red 275 kV, black shows 132 kV and maroon 1-33 kV. However this is purely illustrative as the load is more or less directly connected to the swing node, RICH11, since no impedances are applied to the cables. The model is used for the frequency response studies and to keep the simulations simple, frequency changes will be provoked by active power modulation in the load.
4.2.2 Model for fault studies
For the fault ride through (FRT) studies the faults of interest should be performed on supergrid voltage (275 kV and above). For this reason the swing bus was moved to Canterbury North (400 kV). The short circuit current in this point was known due to Siemens PTI’s pre-study and a new Sbase for the Thevenin equivalent with Zth = 1 p.u.
could be calculated [21].
Isc Ua Sbase
34.29 kA 400 kV 23757 MVA
Table 4.4: Thevenin equivalent CANT400
To keep the load flow stable a load of 300 MW, -11 MVAr was implemented. This yielded the model shown in figure 4.5. This is a simplified model and data for trans- formers and cables are based on typical data rather than actual data. The impedance of the transformer connecting bus 2101 to RICH11 was adjusted in order to have a sig- nificant voltage dip at the PCC.
A dummy bus was implemented to represent the middle of the line connecting bus 2000 and 2101, this one was used for the single line to ground studies whilst solid three phase short circuit faults were applied to bus 2101.
4.3 Dynamic Parameter Set-Up
All simulations are performed with a simulation time step of 5 ms. The dynamic solution parameters are of importance for the simulations and these have been modified from default settings:
Iterations 200
Acceleration 0.1 Delta (Time step) 0.005 Freq. filter 0.02
Table 4.5: Dynamic solution parameters for the simulations
5. Frequency Response
To investigate the frequency response additional active power was injected to the system through a step change in the production at the negative load, i.e. the nuclear plant. To keep the simulations simple, at this stage, only changes in active power was performed.
The grid code from National Grid states that production units must be able to op- erate without tripping up to a system frequency of 52 Hz. It also states that all pro- duction units rated above 50 Hz set into service after 2006 must be able to contribute to frequency control by operation in frequency sensitive mode (FSM). When operated in FSM the deadband must be no greater than± 0.015 Hz and the droop between 3 -5 %.
With this background following settings was applied :The droop was set to 5 %, the dead band± 0.015 Hz, all generating units operated at rated power, e.g. 300 MW and the total system inertia was assumed 5 p.u. In PSS/E the power plant controller (PPC) was activated at time = 1 second and the step change in production was initiated at time = 10 seconds (delayed to make sure the system was stable at the time). Active power was injected to the system via the negative load and was stepped up until the limit of 52 Hz was reached to investigate the wind farm’s capability.
Thereafter the wind farm’s ability to respond to low frequency events was investigated.
For this simulation the wind power production must be constrained below available power. The production was therefore stepped down to 75 % of maximum capacity, i.e.
to 225 MW, but still the maximum capacity was set to 300 MW. Thereafter an increase in load with 75 MW was performed.
The swing bus will only affect the time of the frequency change but will not contribute with any frequency control as no governor is implemented in the swing bus model.
According to figure 5.3 a change in active power is seen, however with no governor im- plemented the swing bus will strive to get back to its pre-fault condition, the time delay in frequency change that this provokes is due to the swing bus inertia.
5.1 High Frequency Events
Figure 5.1 and 5.2 describe the event and illustrate that the limit of 52 Hz is reached after an injection of additional 232 MW, i.e. 77.33 %, to the system. This gives a power reduction of 232 MW as a response from the wind power plant. Expressed in %M/0.1 Hz this yields power reduction of -3.9 % MW/ 0.1 Hz, which is more than the grid code requires (2 % MW/0.1 Hz).
Figure 5.1: Frequency response due to additional 232 MW into the system.
The swing bus will show significant contribution to the frequency change in terms of its inertia and to get an adequate response time it is of importance that the swing bus’
inertia is representative for the overlying net. The inertia is chosen to 5 p.u. due to pre- vious discussion, however it is of importance to add that this swing bus representation does not feature any frequency response to stabilize the frequency. This means that the swing bus will affect the frequency response in terms of how fast the system frequency is changing but stepping down in production is a response only featured by the wind
Figure 5.2: Active power reduction due to additional 232 MW into the system.
Figure 5.3: The swing bus response when adding extra 232 MW at the PCC node.
5.2 Low Frequency Events
To be able to respond to a low frequency event the active power must be constraint below the available power. This means that the capability to respond to low frequency events will vary dependning on how much the wind farm active power is constraint. In this case it is constraint to a level of 75 % of rated capacity, i.e. 225 MW. Figure 5.4 and 5.5 illustrate the gain in active power output due to a reduction in system frequency.
75 MW is added to the load at time= 10 seconds and frequency change can be seen in figure 5.4. Figure 5.5 show the active power production due to the frequency change.
A short time delay before the active power response can be seen, this is due to the dead- band and i excepted behavior. The graph is also illustrating the losses in the seacables as the outgoing power is below the wind turbines’ production (225 MW initially and 300 MW finally).
Figure 5.4: Frequency response due to shortage of 75 MW.
Figure 5.5: Active power production due to a shortage of 75 MW
6. Solid Three-Phase Short Circuit Faults
As stated in the National Grid grid code the fault ride through (FRT) crieteria ap- plies for faults, symmetrical and asymmetrical, on supergrid voltage, i.e. above 200 kV.
The three-phase short circuit fault was applied on node 2101, which is the 275 kV bus closest to point of common coupling (PCC), to cause an as severe voltage dip as possible.
The grid code states that the power park module shall withstand a voltage dip down to 0 p.u. at supergrid voltage for at least 140 ms. Due to impedances the voltage at the turbine terminals will not be 0 p.u. but slightly above.
The fault is applied at time = 1 second, run for 140 ms cleared at time = 1.140 s, thereafter the simulation is run up to 5 s to investigate that the module can retain the pre-disturbed operation without large oscillations.
Since voltage and reactive power control will be carried out by the SVC Plus for Thanet on-site, just dispatching signals to the power plant controller (PPC), the short circuit faults were chosen to be carried out without activation of the PPC.
6.1 Results from Dynamic Simulation
As can be seen in figure 6.1 the voltage will not drop to 0 p.u. at the PCC even though the fault is applied close by. The voltage drops to 0.3 p.u. and the remaining voltage is due to impedance in the transformer connecting node 2101 to RICH11. Investigating the voltage at the wind turbine terminals, figure 6.2, implies an even higer remaining voltage which is expected from the impedances in the sea cables and the internal grid.
Figure 6.1: Voltage dip at PCC due to short circuit fault on the overlying net.
Figure 6.2: Voltage dip at wind turbine terminals due to short circuit fault on the overlying net.
The active power output from the turbines will drop due to the voltage drop as seen in figure 6.3 and 6.4. The grid code requires the active power to be restored proportionally
with the voltage, i.e. a restoration to at least 90 % of the pre-fault level in 0.5 seconds after fault clearance. From the figures this is achieved but just barely. To notice is also the losses in the cables, which is the reason for the wind farm not reaching 300 MW when measured at the PCC, see figure 6.4.
Figure 6.3: Active power due to a short circuit fault on the overlying network.
Figure 6.4: Active power from the entire wind farm.
Figure 6.5 - 6.7 describes the reactive power contribution from one windturbine aggregate (rated 90 MW) and one of the STATCOM devices. The behaviour from the individual system parts are described in figure 6.6 and shows that the STATCOM reaches its rated limit. When measuring at the PCC, figure 6.7, the wind power park contributes with 140 MVAr, which is above the required 98.6 MVAr demanded for a power factor of 0.95.
As no units are tripped it is assumed that no relay-settings are overridden.
Figure 6.8 shows the frequency deviation according to the fault and implies that also the frequency is brought back close to nominal.
Figure 6.5: Reactive power contribution from one wind turbine aggregate.
Figure 6.7: Reactive power contribution from the entire wind farm.
Figure 6.8: Frequency at the PCC node.
6.2 Voltage and Current Contribution
In the load-flow interface a static study regarding the short circuit fault has also been executed. This shows the behavior and the symmetry of the fault, however the results are momentary and the entire voltage drop is not covered in this study. Table 6.1 - 6.4 present the voltages and currents for phase sequence and symmetric sequence due to a short circuit fault applied on node 2101, for node location and definitions please refer to figure 4.5. Both voltage and current are expressed in their RMS values.
Phase Voltage [PU]
Node Vbase [kV] Re(VA) ImVA) Re(VB) Im(VB) Re(VC) Im(VC)
229 132 0.75 0.2 -0.36 -0.66 -0.39 0.64
2101 275 0 0 0 0 0 0
121 132 0.75 0.2 -0.36 -0.66 -0.39 0.64
125 132 0.77 0.03 -0.36 -0.69 -0.42 0.65
Table 6.1: Phase voltage for a solid three-pase short circuit fault applied to bus 2101.
Sequence Voltage [PU]
Node Vbase [kV] Re(V0) ImV0) Re(V1) Im(V1) Re(V2) Im(V2)
229 132 0 0 0.75 0.2 0 0
2101 275 0 0 0 0 0 0
121 132 0 0 0.75 0.2 0 0
125 132 0 0 0.77 0.03 0 0
Table 6.2: Sequence voltage for a solid three-pase short circuit fault applied to bus 2101.
Phase Currents [A]
Node Ibase [A] Re(IA) ImIA) Re(IB) Im(IB) Re(IC) Im(IC)
229 to RICH11 438 1005 -752 -1154 -495 148 1247
Thanet to 2101 210 8.2 -363 -318 174 310 189
121 to 229 438 503 -376 -577 -247 74 623
125 to Seawall 438 499 -270 -484 -297 -15 567
Sequence Currents [A]
Node Ibase [A] Re(I0) ImI0) Re(I1) Im(I1) Re(I2) Im(I2)
229 to RICH11 438 0 0 1005 -752 0 0
Thanet to 2101 210 0 0 8.2 -363 0 0
121 to 229 438 0 0 503 -376 0 0
125 to Seawall 438 0 0 499 -270 0 0
Table 6.4: Sequence current for a solid three-pase short circuit fault applied to bus 2101.
A three-phase short circuit fault is a symmetrical fault, which is clarified by symmetrical sequence only containing a positive sequence. Expressed in phasors the current flowing out of the PCC is:
IA= 1255� 323◦, IB= 1255� 203◦ and IC = 1255� 83◦
It is clear that all phases have the same magnitude with a 120◦ displacement.
6.3 Swing Bus Behavior
It is also of interest to study the contribution from the swing bus, which shall be rep- resenting the system at the connection point. Comparing the frequency as measured at the PCC node and the frequency at the swing-bus node, large differences can be seen in the frequency deviation. As this fault is a short circuit fault applied between the PCC and swing bus one can interpret the results as the wind farm being an isolated system during the fault.
Figure 6.9: Frequency at the swing node, representing the overlying net.
Figure 6.11: Reactive power contribution from swing bus/overlying net.
7. Unsymmetrical Single Line to Ground Fault
7.1 Zero sequence data
When investigating an unbalanced fault PSS/E requires a zero sequence data as it per- forms its calculations in a positive sequence equivalent. This means that the zero se- quence data have to be prepared manually, which was done according to calculations at Vattenfall VRD [22] if not stated otherwise.
In PSS/E the zero sequence data file was built up step-wise by:
• Defining the positive and negative sequence of the wind machines, calculated to:
0.0066 + j0.2110 p.u. The zero sequence was ignored, i.e. set to 0 +j0.
• Defining data sequence for the swing node, which was set as 0 + j1 as default [24]
• The cable sequences were set to the following:
– 1000mm2 cable, 2.5 km: z0 = 0.0036 + j0.0086 p.u.
– 630 mm2 cable, 24.3 km: z0 = 0.03535 + j0.0095 p.u – 300-600 mm2 cable, 8 km: 0.05877 + j0.1983 p.u.
– 275 kV OHL, 2km: 0.00037 + j0.0034 p.u. [23]
– The positive and negative sequence was ignored as it is not required for the zero sequence data file.
• The transformer data was identified as: z0 = j0.22 p.u. for the three-winding
The wind turbine generator transformers and the three-winding transformers connecting the four internal radials are all Y-Delta connected. This means that they will give no contribution in zero sequence current and their zero sequence impedance can be regarded infinitely large.
7.2 Voltage and Current Contributions
To estimate the voltage profiles and the current contribution the unbalanced fault is applied in load-flow. The fault is applied as a single-line to ground fault at phase A at a dummy bus, which represents the middle of the line between node 2101 and 2000 which is a 275 kV OHL at the overlying net. This method is according to [24], that states that line faults will be translated into bus faults in PSS/E.
Figure 4.5 shows the single-line network which was used for the unbalanced fault analy- sis. Node 229 is the PCC node summing the two wind farm cables up and connecting to the overlying net (RICH11). Node 121 is the node connecting one of the identical cables with SVC Plus device and is connected to 229 via a zero impedance cable. Hence 121 represents the same voltage as at 229 but carries only half of the current, i.e. half the production from the wind farm.
Node 125 is the node connecting to one of the two three-winding transformers sum- ming two of the wind farm radials. 125 is located in the same radial as 121. One can see (from the zero sequence current) that the three winding transformer configuration is of Y-Delta type as all zero sequence current is blocked herein.
When presenting the current in the dummy bus it is with regard to the currents from the wind farm.
Values presented are given as momentary RMS values.
Phase Voltage [PU]
Node Vbase [kV] Re(VA) ImVA) Re(VB) Im(VB) Re(VC) Im(VC)
229 132 0.88 -0.06 -0.54 -0.83 -0.34 0.89
Dummy 275 0 0 -0.34 -0.86 -0.26 0.85
125 132 0.88 -0.06 -0.54 -0.83 -0.34 0.89
121 132 0.89 -0.03 -0.52 -0.85 -0.37 0.89
Table 7.1: Momentary phase voltage for a solid single line to ground fault applied to the dummy bus.
Table 7.1 shows clearly that the fault is applied on phase A as the voltage drops to zero for this phase at the dummy bus, the voltages for phase B and C (at the dummy node)
on the other hand will not equal the line-to-line voltage as described in section 2.3 as they, expressed in phasors do not have the same magnitude or the 150◦ displacement:
VB = 0.90� 68◦ VC = 0.89� − 73◦
Due to impedances the voltage on the other buses will not drop to zero. At the buses 229, 125 and 121 the voltage difference between the phases are not significant.
Sequence Voltage [PU]
Node Vbase [kV] Re(V0) ImV0) Re(V1) Im(V1) Re(V2) Im(V2)
229 132 0 0 0.93 -0.09 -0.06 0.03
Dummy 275 -0.20 -0.01 0.59 -0.02 -0.39 0.03
125 132 0 0 0.95 -0.06 -0.05 0.03
121 132 0 0 0.93 -0.09 -0.06 0.03
Table 7.2: Sequence voltage for a solid single line to ground fault appliied to the dummy bus.
Phase Current [A]
Node Ibase [A] Re(IA) ImIA) Re(IB) Im(IB) Re(IC) Im(IC)
229 to RICH11 438 1149 -434 -700 -889 -449 1323
Thanet to Dummy 210 -5 -180 -15 107 20 78
125 to Seawall 438 581 -93 -232 -519 -348 612
121 to 229 438 575 -284 -350 -445 -225 662
Table 7.3: Phase currents for a solid single line to ground fault applied to the dummy bus.
Sequence Current [A]
Node Ibase [A] Re(I0) ImI0) Re(I1) Im(I1) Re(I2) Im(I2)
229 to RICH11 438 0 0 1213 -290 -64 -145
Thanet to Dummy 210 -0.04 2 -11 -101 6 -80
125 to Seawall 438 0 0 617 -13 -36 -80
I2. In the same manner it is easy to verify that I0= 13(IA+ IB+ IC).
The current flowing from the PCC, expressed in phasors:
IA= 1128� 339◦, IB= 1132� 232◦ and IC = 1397� 289◦.
7.3 Dynamic Simulation
When performing dynamic simulations PSS/E is operating in positive-sequence equiva- lent of the power system and does not feature any possibility to show negative and zero sequences.
However, the solution obtained from the static study only provides the momentary re- sponse values and as these will change with time it is of interest to perform a dynamic study as well. The grid code states the demand on the wind farm being able to ride- through balanced and unbalanced faults for at least 140ms.
A simulation is set up similar to the one regarding balanced faults, with a single-line to ground fault (the most common type of fault) applied on the dummy bus. Reactive power and voltage will be controlled by the SVC Plus only. As stated the dynamic simulation only provides a solution from the positive sequence.
Figure 7.1: Voltage profile at the PCC when applying a single line to ground fault at the dummy bus
Figure 7.2: Active power supplied by one wind turbine aggregate when applying a single line to ground fault at the dummy bus
