Grid Compatibility of Wind Generators with Hdyro

Transcription

P1347. 29th of August 2008
Grid Compatibility of Wind Generators with
Hdyro-Dynamically Controled Gearbox with
German Grid Codes
Draft Report
prepared for
Voith Turbo Wind GmbH & Co. KG
DIgSILENT GmbH
Heinrich-Hertz-Strasse 9
D-72810 Gomaringen
Tel.: +49 7072 9168 - 0
Fax: +49 7072 9168- 88
http://www.digsilent.de
e-mail: [email protected]
Please contact
Markus Pöller
Tel.: +49-7072-9168 57
e-mail: [email protected]
Prepared for:
Voith Turbo Wind GmbH &
CoKGVothstr. 1Germany, 74564
Crailsheim
Grid Compatibility of Wind Generators with Hdyro-Dynamically Controled Gearbox with German
Grid Codes
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Table of Contents
Table of Contents
1 Introduction ......................................................................................................................................... 5
2 Description of the 2 MW Wind Turbine Model including WinDrive .................................................... 6
2.1 Wind Turbine Model ...............................................................................................................................8
2.2 Voltage Controller and Excitation System..................................................................................................9
2.3 WinDrive and Drive Train Model ............................................................................................................ 10
2.4 WinDrive Control.................................................................................................................................. 12
2.5 Pitch Control and Aerodynamic Model .................................................................................................... 13
3 Verification of the PowerFactory Model............................................................................................ 15
4 Wind Farm Network........................................................................................................................... 17
4.1 Test Wind Farm with HV (110kV) Connection Point ................................................................................. 17
4.2 Test Wind Farm with MV (10kV) Connection Point................................................................................... 19
5 Requirements for Connections to the Transmission (HV) Grid ........................................................ 21
5.1 Active Power Output (Section 3.3.13.3 in [1]) ......................................................................................... 22
5.2 Reactive Power Output (Section 3.3.8 in [1]) .......................................................................................... 22
5.3 Behaviour during Disturbances in the Network ........................................................................................ 24
5.3.1 Transient Stability after Short-Circuits (section 3.3.13.5 resp. 3.3.12.1 in [1]) ....................................... 24
5.3.2 Oscillatory Stability (section 3.3.12.2 in [1])....................................................................................... 25
6 Requirements for Connections to the Distribution (MV) Grid .......................................................... 29
6.1 Network Disturbances........................................................................................................................... 30
6.1.1 Steady-State Voltage Changes (Section 2.3 in [2]) ............................................................................. 30
6.1.2 Voltage Change due to Switching Operations (section 2.4.1 in [2]) ...................................................... 30
6.1.3 Long-Term Flicker (Section 2.4.2 in [2]) ............................................................................................ 32
6.1.4 Harmonics (Section 2.4.3 in [2]) ....................................................................................................... 33
6.1.5 Commutation Voltage Drops (Section 2.4.4 in [2]).............................................................................. 34
6.1.6 Impact on Ripple Control (Section 2.4.5 in [2]) .................................................................................. 34
6.2 Behaviour of the Generator ................................................................................................................... 35
6.2.1 Transient Network Support – Low-Voltage Ride-Through (Section 2.5.1.2 in [2]) .................................. 35
6.2.2 Short-Circuit Current (Section 2.5.2 in [2]) ........................................................................................ 36
6.2.3 Active Power Output (Section 2.5.3 in [2])......................................................................................... 36
6.2.4 Reactive Power Output (Section 2.5.4 in [2]) ..................................................................................... 37
7 Conclusion.......................................................................................................................................... 39
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Table of Contents
8 References ......................................................................................................................................... 40
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P1347
1 Introduction
The purpose of this study is to analyse the compatibility of the DeWind 2MW (D 8.2) wind generator, which is
equipped with the Voith WinDrive system and synchronous generator with the technical requirements of the
relevant BDEW connection conditions, which are:
•
Transmission Code 2007 [1] for wind farms with connection point at 110kV or above and
•
Technische Richtlinie, Erzeugungsanlagen am Mittelspannungsnetz [2]
From 2009 on, these technical requirements will also be the basis for obtaining the “Systemdiensleistungsbonus”,
which will be introduced by the new version of the German Renewable Energy Law (EEG).
The studies have been carried out using a
•
50MW wind farm for connection to a HV (110kV) connection point
•
20MW wind farm for connection to a MV (10kV) connection point
The technical behaviour of these wind farms has been analysed for different short circuit levels at the connection
point and benchmarked against the relevant requirements of the technical standards.
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2 Description of the 2 MW Wind Turbine
Turbine Model including WinDrive
WinDrive
Based on information provided by Voith Turbo Wind (models inclusive routines based on the control software of
the wind turbine D 8.2), an updated dynamic model and routines of a wind turbine including variable dynamicallycontrolled speed gearbox and directly grid-coupled synchronous generator (2 MW) is implemented in the
simulation software PowerFactory. The accuracy of the model is chosen to be suitable for analysing different
effects of power system stability problems.
The model (delivered by Voith Turbo Wind) consists of the following components, which are modelled in detail:
•
Synchronous generator including voltage control (VCO) and excitation system
•
Multi-mass shaft model
•
WinDrive - variable speed gearbox (simplified) including complete drive train
•
WinDrive and guide vane control
•
Speed control
•
Pitch angle control
•
Aerodynamics of the turbine model
Voith Turbo provided a Matlab model including the complete drive train and its control as well as the turbine
characteristic and pitch control. This model has been transferred to PowerFactory into a DSL model.
The Matlab model also contains a simplified generator model. PowerFactory supports a detailed build-in generator
model, which is suitable for transient simulations and which is used during the investigation. For this model of a
2 MW wind generator with a rated voltage of 10kV a set of electrical parameters has been provided. Table 1 and
Table 2 lists the electrical parameters of the synchronous generator model including saturation. The rated
frequency of the wind farm grids is assumed to be 50 Hz in all simulations.
As the PowerFactory generator model has a different behaviour in comparison to the simplified Matlab model,
both models have been compared by open loop tests. The verification of the model is shown in the next chapter.
All data has been provided by Voith Turbo GmbH & Co. KG.
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Table 1: Parameter Definition of the Synchronous Generator Models
Parameter
Description
Unit
Generator
Sr
Rated Mechanical Power
kVA
2222
Ur
Rated Voltage
kV
cos(phi)
Rated Power Factor
Pr
Rated Mechanical Power
kW
2000
n
Nominal Speed
rpm
1500
fel
Nominal Frequency
Hz
50
pz
No of Pole Pairs
ra
stator resistance
p.u.
0.0076
xl
stator leakage reactance
p.u.
0.072
xd (total)
d-axis synchronous reactance
p.u.
1.52
xq (total)
q-axis synchronous reactance
p.u.
0.996
x'd (total)
d-axis transient reactance
p.u.
0.152
x''d (total)
d-axis subtransient reactance
p.u.
0.116
x''q (total)
q-axis subtransient reactance
p.u.
0.192
T’d
d-axis open circuit transient time constant
S
0.208
T’’d
d-axis open circuit subtransient time
S
0.022
S
0.011
10
0.9
2
constant
T’’q
q-axis open circuit subtransient time
constant
Jgen
Rotor Inertia
kg m²
109.0223
Ta
Acceleration Time Constant (rated to Pr)
s
1.36968
Table 2: No-load Saturation Curve Parameters
Terminal Voltage
Unit
Value
Field Current
Unit
Value
V0
pu
0
Ifd0
pu
0
V1
pu
0.5
Ifd1
pu
0.45
V2
pu
0.75
Ifd2
pu
0.69
V3
pu
1.
Ifd3
pu
1
V4
pu
1.15
Ifd4
pu
1.37
V5
pu
1.25
Ifd5
pu
1.95
Table 3: Operation Points from the Capability Diagram at u=1p.u.
P / MW
2.00
cos(ϕ
ϕ)
0.9
Q/Sr / p.u.
Q / Mvar
0.436
0.969
-0.436
-0.969
0.710
1.578
-0.580
-1.289
(overexcited)
2.00
0.9
(underexcited)
0.00
0.00
0.0
(overexcited)
0.0
(underexcited)
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DIgSILENT
2.1 Wind Turbine Model
Frame Wind-Turbine:
u
speed_Gen
Pitch Adjust
ElmPit*
beta_ist
vw
Turbine
ElmTur*
M_Blatt1
beta_soll
M_Blatt2
beta_soll
M_Blatt3
Pitch Control
ElmPit*
ve
VCO
ElmVco*
pt
Shaft/Gearbox
ElmComp*
SyncParallel
Generator
ElmSym*
M_Abtrieb
SyncEnable
WinDrive Ctrl
ElmComp*
Href
GVP_Start
omega_rotor
WinDriveSpeed
Pact
Figure 1: Schematic Block Diagram of the Voith Wind Turbine Model
Voith Turbo GmbH provided an updated model of the mechanical part including gearbox, clutches and mass-shaft
models as well as the WinDrive control in form of a Matlab Simulink model including a set of parameter for a
50 Hz turbine. The model represents a simplified representation of the WinDrive model, which is suitable for
analyzing system stability aspects.
This model is implemented in the simulation software PowerFactory using block diagrams and the internal
simulation language DSL. A benchmark of the PowerFactory model against the original Matlab model has been
carried out to verify the model used for further studies.
Figure 1 shows the schematic structure of the model including synchronous generator, excitations system and
drive train. Turbine aerodynamics and pitch controller are not included in the model because it can be assumed,
that wind speed and thus turbine power is constant during the simulation time.
The results of the model verification are described and shown in chapter 3.
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DIgSILENT
2.2 Voltage Controller and Excitation System
vco_ESAC5A: 1992 IEEE Type AC5A Excitation System
usetp
0
Vrmax
u
1/(1+sT)
Tr
ur
-
du
-
duo
{K/(1+sT)}
Ka,Ta
duos
[1/sT
Te
-
uerrs
Vrmin
us
ustab
1
duo1
uek
(1+sTb)/(1+sTa)
Tf2,Tf3
K
Ke
vx
_sTb_/(1+sTa)
Kf,Tf1
Se(efd)
E1,Se1,E2,Se2
Figure 2: Schematic Block Diagram of the Voltage Controller Model (VCO) ESAC5A
Table 4: Parameter Definition of the Voltage Controller
Parameter
Description
Unit
Values
Tr
Measurement Delay
s
0.01
Ka
Controller Gain
p.u.
40
Ta
Controller Time Constant
s
0.1
Ke
Excitor Constant
p.u.
1
Te
Excitor Time Constant
s
0.2
Kf
Stabilization Path Gain
p.u.
0.05
Tf1
Stabilization Path 1th Time Constant
s
0.35
Tf2
s
0.1
Tf3
s
0
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Parameter
Description
Unit
Values
E1
Saturation Factor 1
p.u.
1.96
Se1
Saturation Factor 2
p.u.
1.06
E2
Saturation Factor 3
p.u.
1.47
Se2
Saturation Factor 4
p.u.
0.71
Vrmin
Controller Minimum Output
p.u.
0
Vrmax
Controller Maximum Output
p.u.
10
DIgSILENT
2.3 WinDrive and Drive Train Model
Triebstrang Frame:
M_Blatt1
0
0
M_Blatt2
1
1
M_Blatt3
2
M_Hauptwelle
2
omega_Nabe
Rotor
ElmRot*
0
3
0
0
Antrieb
ElmAnt*
1
0
0
M_Antrieb
omega_Antrieb
1
3
Href
Clock
*
4
0
cl
SampleHold
*
H_soll
Hydr_Antrieb
ElmHyd*
H
1
1
GVP_Start
HSC
ElmHsc*
n_WD_in
1
2
2
3
3
1
M_Abtrieb
omega_Abtrieb
0
5
speed_Gen
0
pt
Shaft HSC-VBK 1
ElmSha*
1
2
2
n_Gen
Figure 3: Schematic Block Diagram of the Multi-Mass Shaft Model of the Voith Wind Turbine including WinDrive
Figure 3 shows the block diagram of the complete drive train including WinDrive. This model represents the
mechanical spring-mass system of the shaft system of the rotor and of the shaft between generator and
WinDrive. In PowerFactory , the generator inertia is integrated in the synchronous machine model and is
therefore not modelled separately.
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P1347
DIgSILENT
The model of the actual WinDrive hydrodynamic gearbox is shown in Figure 4.
HSC WinDrive Model:
rad/s -> rpm
M_Antrieb
0
1
M_Abtrieb
0
M_Abtrieb_neg
-1
omega_Antrieb
0
1
omega_Abtrieb
WinDrive
1
z_Hohlrad_UG,z_Sonne_UG,J_Tr..
n_WD_in
0
1
2
2
2
omega_Turbine
M_Pumpe
M_Turbine
3
0
0
nue
Nue
1
0
Torque Converter
T_Wandler,rho_Oel,D_Prof..
1
abs_min_omega_Pumpe
1
2
2
3
H
0
GVP_Start
H_inc
1
Figure 4: Schematic Block Diagram of the WinDrive Model
The parameter sets of all components are provided by Voith Turbo GmbH. The parameters are taken from the
Matlab model “WinDrive_Tauschmaschine_Cuxhaven_Data_Rev08”. They are not listed here in detail.
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P1347
DIgSILENT
2.4 WinDrive Control
WinDriveCtrl Frame:
GVP_Start
0
0
Rotorkennlinie1
ElmRot*
Psoll
H_vorst
2
0
0
1
WinDriveSpeed
Pact
0
0
Signal Vorfilterung1
ElmSig*
1
2
1
n_WD_in_fast
2
n_WD_in_slow
SyncParallel
ElmSyn*
3
Pcurr_KPP
H_Netzbetrieb
SyncParallel
0
TVSActive
0
1
SyncEnable
1
Verschliff
ElmVer*
4
GVP
SubSys
ElmSub*
Href
1
2
2
H_Sync
3
SyncEnable
2
speed_Gen
FDelta Calc
ElmFDe*
FDelta
0
SyncMode
ElmSyn*
1
Figure 5: Schematic Block Diagram of the WinDrive Control
The WinDrive controller is providing the guide vane position (“GVC” or “Href”) to the mechanical WinDrive model.
As a feedback the speed of the WinDrive “WinDriveSpeed” is used.
The parameter sets of all components are provided by Voith Turbo GmbH. The parameters are taken from the
Matlab model “WinDrive_Tauschmaschine_Cuxhaven_Data_Rev08”. They are not listed here in detail.
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DIgSILENT
2.5 Pitch Control and Aerodynamic Model
Pitch Control:
Schaltbedingung
0
D_pitch
D_pitch
dbeta
1
90
beta_ist
0
1
omega_rotor
n_rotor_soll
0
rad/s -> rpm
n_rotor
Schaltbedingung
n_eck,beta_grenz
-
Select
n_rotor_nenn,n_ec..
dn
90
Rotor Speed Ctrl pitch_soll
P_pitch_pos,P_pit..
beta
Limiter
beta_soll
1
0
0
DIgSILENT
Figure 6: Schematic Block Diagram of the Pitch Controller
Pitch Adjustment:
max_geschw..
beta_soll
dbeta2
-
K
pitch..
yi
Delay
pitch_Totzeit
yi1
Limiter
yi2
max_beschl..
RateOfChangeLim
0.001
yi3
1/s
beta2
dbeta
-
K
KVrea..
yi5
1/s
beta_ist
Figure 7: Schematic Block Diagram of the Pitch Adjustment
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P1347
Table 5: Parameter Definition of the Pitch Control and Adjustment
Parameter
Description
Unit
Values
max_beschleunigung_pitch
Maximale
deg/s²
60
deg/s
5.5
0.05
Blattwinkelverstellbeschleunigung
max_geschwindigkeit_pitch
Maximale
Blattwinkelverstellgeschwindigkeit
pitch_Totzeit
Totzeit des Reglers
s
pitch_amplification_factor
Reglerverstärkung
p.u.
13
KVreal_pitch
Kehrwert der Verzugszeit
1/s
10
maximum_pitch_adjustment_speed
deg/s
9.5
n_rotor_nenn
1/min
18.6
n_eck
1/min
18.193
beta_grenz
deg
3
P_pitch_pos
deg/rpm
5
P_pitch_neg
deg/rpm
6
I_pitch_pos
deg/rpm/s
0.5
I_pitch_neg
deg/rpm/s
2
D_pitch
5.7
Table 6: Parameter Definition of the Turbine Model
Parameter
Description
Unit
Values
R
Rotor Radius
m
40.15
rho_luft
Density of Air
Kg/m³
cp
cp-lambda-Characteristic
1.225
see Matlab model
Pitch angle control and turbine aerodynamics are not taken into account during the analysis of the steady-state
as well as transient and oscillatory stability aspects. Due to large time constants, these models their influence the
simulations can be neglected.
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P1347
3 Verification of the PowerFactory Model
In this chapter the model of the Voith wind turbine, which is implemented by DIgSILENT GmbH in the simulation
software PowerFactory, is verified by comparing the results of a simulation with the results obtained with the
corresponding Matlab model.
As the Matlab model is using a simplified synchronous generator and no network model, the verification is carried
out using an open-loop test of the model in Matlab and in PowerFactory. To do this the results from the Matlab
simulation are fed as input signals into the PowerFactory model. These signals are the generator speed
“n_Generator” and the electrical power “P_Gen”. The output signals of the different blocks of both models are
then checked to be identical and thus to verify the dynamic response of the models.
The simulation is performed in PowerFactory and Matlab using the following sequence:
•
Initialising the model with all rotational speed equal to zero.
•
The model is settling to a steady-state operation point at Pgen = 0 MW.
•
Start of a ramp onto the blade torques M_Blatt1, M_Blatt2 and M_Blatt3 at t=50 s, where the value is
increased linearly from 0 Nm to 330’000 Nm with a gradient of 20’000 Nm/s.
•
This will in turn increase the electrical power to a value of Pgen = 1.8 MW.
The simulations are carried out for a simulation time of 100 s. A fixed time step of 2 ms is used for both
simulations. The results of both the PowerFactory and Matlab are shown in the plots on the next pages. The
following variables of the models are visualised:
Drive train:
•
the rotational speed omegaAntrieb and the torque MAntrieb as well as omegaAbtrieb and the torque MAbtrieb.
•
rotational speed of the generator omegaGen and the set point for the guide vane control Hsoll and H.
•
torque of the main shaft MHauptwelle and the rotational speeds omegaHauptgetriebe and omegaRotor.
WinDrive control:
•
WinDrive speed and outputs of the signal input filter.
•
Outputs of the rotor characteristics Psoll and Hvorst resp. Hgefiltert
•
Guide vane control setpoint and output MNetzbetrieb, GVP and Href
Grid Codes
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The plots for the verification are shown in Annex 1. The results from the PowerFactory simulations are shown in
red (solid curve) and the results from Matlab are shown in blue (dashed curve).
The plots show that both simulations match very well. The model implemented into PowerFactory shows in the
mechanical part as well as in the different control modes identical behaviour compared to the Matlab model. Thus
the model can be used to be integrated into a detailed wind farm grid, to analyse the realistic behaviour of the
wind turbines during disturbances and faults in the network.
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P1347
4 Wind Farm Network
For analysing the compatibility of the Voith wind turbine concept to the German requirements for the connection
to high voltage (HV) [1] and medium voltage (MV) [2] networks, the behaviour of a complete wind farm is
investigated.
The behaviour of the wind turbines with directly grid-coupled synchronous generators and variable speed gearbox
is analyzed on the basis of typical wind farm layouts, which are described in this chapter.
4.1 Test Wind Farm with HV (110kV)
(110kV) Connection Point
The steady-state and dynamic performance of a wind farm is analyzed based on a wind farm layout with a total
rated power of 50 MW and a nominal frequency of 50 Hz. The wind generators are arranged in 5 strands each
connecting 5 wind turbines with a rating of 2 MW each. Each generator has a rated voltage of 10 kV, which
corresponds to the wind farm internal voltage level. The wind farm is connected to the 110kV connection point by
a 10kV/110kV step-up transformer.
The distances between the turbines on a strand are assumed to be 500 m. The different strands are 1000 m
apart. The wind farm configuration is shown in Figure 8.
There are three different cable types used in the wind farm network. All cables are XLPE cables with a rated
voltage of 10 kV and the laying procedure is in a flat formation (row). The cable types used and wind farm
topology applied have been agreed with Voith Turbo. The cables are selected based on thermal considerations.
For the connection of each strand to the main substation, two parallel cable systems (6x240RM) are used. Cable
data is based on the DIN/IEC standard and is taken from reference [3], the data is listed in Table 7.
Table 7: Characteristic Values of the used IEC Standard Cables [3]
Cable Type
Ur
kV
Ir
kA
Sr
MVA
R1’
Ω/km
R0’
Ω/km
X1’
Ω/km
X0’
Ω/km
C1’=C0’
µF/km
N2XS2Y 1x240RM
6/10kV ir
10
0.546
9.77
0.0754
0.701
0.180
0.293
0.456
N2XS2Y 1x70RM
6/10kV ir
10
0.303
5.25
0.286
1.087
0.215
0.555
0.283
NA2XS2Y 1x240RM
6/10kV ir
10
0.453
7.85
0.125
0.751
0.180
0.293
0.456
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S1G5
HVWI804D_WDG81
~
G
S1G4
HVWI804D_WDG81
~
G
S1G3
HVWI804D_WDG81
~
G
S1G2
HVWI804D_WDG81
~
G
S1G1
HVWI804D_WDG81
~
G
bb_S1
10.00 kV
bb_S1G1
10.00 kV
bb_S1G2
10.00 kV
bb_S1G3
10.00 kV
bb_S1G4
10.00 kV
bb_S1G5
10.00 kV
X_S1
cb_S1_G3G4
cb_S1_G1G2
N2XS2Y 1x70RM 6/10kV ir
cb_S1_G4G5
cb_S1_G2G3
0.50 km
0.50 km
0.50 km
0.50 km
S2G4
HVWI804D_WDG81
~
G
S2G3
HVWI804D_WDG81
~
G
S2G2
HVWI804D_WDG81
~
G
S2G1
HVWI804D_WDG81
~
G
bb_S2
10.00 kV
bb_S2G1
10.00 kV
bb_S2G2
10.00 kV
bb_S2G3
10.00 kV
bb_S2G4
10.00 kV
bb_S2G5
10.00 kV
cb_WP_S1
NA2XS2Y 1x240RM 6/10kV ir
0.50 km
S2G5
HVWI804D_WDG81
~
G
X_S2
S3G4
HVWI804D_WDG81
~
G
S3G3
HVWI804D_WDG81
~
G
S3G2
HVWI804D_WDG81
~
G
S3G1
HVWI804D_WDG81
~
G
bb_WP_LV
10.00 kV
S3G5
HVWI804D_WDG81
~
G
cb_WP_S2
1.50 km
cb_S2_G3G4
cb_S2_G1G2
cb_S2_G4G5
cb_S2_G2G3
0.50 km
0.50 km
0.50 km
0.50 km
bb_WP_HV
110.00 kV
bb_S3
10.00 kV
tr_WP
60.00 MVA
10.00 %
cb_S3_G3G4
cb_S3_G1G2
cb_S3_G4G5
cb_S3_G2G3
0.50 km
0.50 km
0.50 km
0.50 km
S4G4
HVWI804D_WDG81
~
G
S4G3
HVWI804D_WDG81
~
G
S4G2
HVWI804D_WDG81
~
G
S4G1
HVWI804D_WDG81
~
G
bb_S4
10.00 kV
bb_S4G1
10.00 kV
bb_S4G2
10.00 kV
bb_S4G3
10.00 kV
bb_S4G4
10.00 kV
bb_S4G5
10.00 kV
cb_WP_S5
0.50 km
Voith
DIgSILENT
PowerFactory 14.0.506
X_S4
cb_S4_G3G4
cb_S4_G1G2
cb_S4_G4G5
cb_S4_G2G3
0.50 km
0.50 km
0.50 km
0.50 km
S5G4
HVWI804D_WDG81
~
G
S5G3
HVWI804D_WDG81
~
G
S5G2
HVWI804D_WDG81
~
G
S5G1
HVWI804D_WDG81
~
G
bb_S5
10.00 kV
bb_S5G1
10.00 kV
bb_S5G2
10.00 kV
bb_S5G3
10.00 kV
bb_S5G4
10.00 kV
bb_S5G5
10.00 kV
Wind Farm Layout
Voith Wind Turbine Modelling
Connection to HV Network
S5G5
HVWI804D_WDG81
~
G
cb_WP_S4
1.50 km
S4G5
HVWI804D_WDG81
~
G
110kV Netz
bb_S3G1
10.00 kV
bb_S3G2
10.00 kV
bb_S3G3
10.00 kV
bb_S3G4
10.00 kV
bb_S3G5
10.00 kV
cb_WP_S3
2.50 km
X_S3
X_S5
cb_S5_G3G4
cb_S5_G1G2
cb_S5_G4G5
cb_S5_G2G3
0.50 km
0.50 km
0.50 km
0.50 km
Project: P1347
Graphic: WF Grid Docu
Date:
8/7/2008
Annex:
DIgSILENT
Figure 8: Wind Farm Layout for Connection to HV-Networks
Grid Codes
-18-
P1347
The electrical parameters of the step-up transformers with tap changer are listed in Table 8.
Table 8: Characteristic Values of the Wind Farm Transformer
Transformer Type
110 / 10 kV YNd5
Tap Changer
Sr / MVA
uk / %
uk0 / %
60
10
10
Add. Volt
per tap / %
Min. Pos
Max. Pos.
1.5
-10
10
Copper Losses
/ kW
ukr0 / %
200
0.333
For all investigated cases strong wind conditions are assumed, e.g. all wind generators are operating above
nominal wind speed, thus all generators are providing rated active power of 2 MW. The total power output of the
farm is about 50 MW. The power factor at the PCC is controlled to 0 Mvar in steady-state.
The results from the load-flow calculation for the base case are shown in Annex 2.
4.2 Test Wind Farm with MV (10kV) Connection Point
The German requirements for the connection to the medium voltage (MV) network are tested using a smaller
wind farm with Voith wind generator technology. The wind farm is connected directly to the 10kV distribution
network, without any step-up transformer.
The performance of the directly grid-coupled synchronous generators with variable speed gearbox with a rated
power output of 2 MW is analyzed and the compatibility with the requirements in the “Mittelspannungsrichtlinie
2008” [2] is shown.
Therefore a wind farm is used based on a wind farm layout with a total rated power of 20 MW at a nominal
frequency of 50 Hz. The generators are arranged in 2 strands each connecting 5 wind turbines with a rating of
2 MW each. Each generator has a rated voltage of 10 kV. This layout and electrical components used are identical
to two of the 5 strands from the 50 MW wind farm described in the previous section for the connection to a HV
network.
Figure 9 shows the wind farm grid used for the calculations including cable types and lengths.
Grid Codes
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Grid Codes
S1G2
HVWI804D_WDG81
~
G
bb_S1G2
10.00 kV
S1G3
HVWI804D_WDG81
~
G
bb_S1G3
10.00 kV
S1G4
HVWI804D_WDG81
~
G
bb_S1G4
10.00 kV
bb_S1G5
10.00 kV
Voith
DIgSILENT
S2G2
HVWI804D_WDG81
~
G
bb_S2G2
10.00 kV
S2G3
HVWI804D_WDG81
~
G
bb_S2G3
10.00 kV
S2G4
HVWI804D_WDG81
~
G
X_S2
X_S1
bb_S1
10.00 kV
bb_S2G4
10.00 kV
bb_S2G5
10.00 kV
PowerFactory 14.0.506
cb_S2_G3G4
cb_S2_G1G2
cb_S2_G4G5
cb_S2_G2G3
0.50 km
0.50 km
0.50 km
0.50 km
S2G1
HVWI804D_WDG81
~
G
bb_S2G1
10.00 kV
S2G5
HVWI804D_WDG81
~
G
cb_S1_G3G4
cb_S1_G1G2
cb_S1_G4G5
cb_S1_G2G3
0.50 km
0.50 km
0.50 km
0.50 km
S1G1
HVWI804D_WDG81
~
G
bb_S1G1
10.00 kV
S1G5
HVWI804D_WDG81
~
G
cb_WP_S2
1.50 km
cb_WP_S1
0.50 km
DIgSILENT
P1347
110kV Netz
bb_WP_LV
10.00 kV
bb_S2
10.00 kV
Voith Wind Turbine Modelling
Connection to MV Network
Wind Farm Layout
Project: P1347
Graphic: WF Grid Docu
Date:
8/7/2008
Annex:
Figure 9: Wind Farm Layout for Connection to MV-Network
-20-
P1347
5 Requirements for Connections to the Transmission (HV) Grid
For the connection of power plants to the transmission network level in Germany, the German grid code
“TransmissionCode 2007” [1] published by the VDN e.V. – Verband Deutscher Netzbetreiber defines the technical
requirements for the generators. In this chapter the different requirements are analysed and the compatibility of
the wind turbine concept using a hydro-dynamically controlled gearbox (WinDrive) is investigated. The
corresponding calculations and simulations are described and the results are shown.
The layout of the wind farm with 25 x 2 MW wind turbines is shown in the previous chapter. The wind farm is
connected to the transmission grid at the 110 kV voltage level. Each wind turbine is modelled in detail, as
described in section 2.
For assessing the dynamic behaviour of the turbines under different network configurations, three different shortcircuit levels at the point of common coupling (PCC) have been assumed:
•
Strong network:
Sk’’=1000 MVA
(SCR=20)
•
Weak network:
Sk’’=300 MVA
(SCR=6)
•
Very weak network:
Sk’’=200 MVA
(SCR=4)
In a previous study the behaviour of the wind generators during different wind scenarios has been analysed. As a
result of the simulation it can be concluded, that the strong wind scenario (wind speeds larger than nominal wind
speed) is the worst case regarding the stability and fault ride-through of the turbines. Thus all calculations have
been performed assuming full power output of 2 MW of all wind generators.
For several of short circuit levels at the connection point, the following stability aspects have to be analysed
according to the “TransmissionCode 2007”, section 3.3.13 “Requirements upon generating units using renewable
energy sources” [1]:
•
Active power output
•
Reactive power output
•
Behaviour during network disturbances
Grid Codes
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P1347
5.1 Active Power Output (Section 3.3.13.3 in [1])
Section 3.3.13.3 describes the requirements of the grid code regarding the active power output of the wind
power plant with regard to deviations of the network frequency from its nominal value.
The wind generator must disconnect, if the network frequency is outside the range of 47.5 Hz to 51.5 Hz. If the
frequency increases above 50.2 Hz, the active power output has to be reduced linearly. Also the transmission
system operator must be able to reduce the active power output using of the complete wind farm in emergency
cases. This ability has to be implemented into the control of the turbine to comply with the requirements.
5.2 Reactive Power Output (Section 3.3.8 in [1])
The requirements concerning the output of reactive power and voltage control at the PCC is similar for
conventional power plants and for generators using renewable energy sources in section 3.3.8 in [1].
Three different figures 3.3a to 3.3c are defining requirements for the steady-state reactive power support of the
plant to the network at the PCC. The values of reactive power output at rated active power are depending on the
voltage at the PCC. The TSO can then select one of the variants relevant for its network.
Figure 10 shows the different curves of the reactive power output in p.u. depending on the voltage at the PCC,
where the dashed curves indicate the requirements according to [1].
The reactive power output capability of the wind farm has been tested using a series of load-flow calculations.
The voltage at the PCC is set by the external network and the individual generators are controlled to provide
maximum and minimum reactive power output according to the capability diagram (see also Table 3 in a previous
chapter). It is then checked, if the reactive power value at the PCC is matching or exceeding the requirements.
Because the requirements according to section 3.3.8 of the TC2007 [1] can be seen as requirements for “slow
reactive power control”, it is assumed that the required reactive range must be covered in the time frame of
minutes, hence with the support of the on load tap changer of the step-up transformer and possible with the
support of mechanically switched capacitor banks. It can further be assumed that the range of the on load tap
changer of the 10kV/110kV is able to maintain the voltage at the 10kV main bus bar at around nominal voltage.
As a resulting curve the reactive power capability of the wind farm with the generators at maximum and at
minimum reactive power output is shown in Figure 10 as a red solid curve. It can be seen, that the wind farm
exceeds the required reactive power range for underexcited operation (consumption of reactive power at PCC),
whereas the maximum requirements are not met for overexcited operation (support of reactive power at PCC).
The reason for this are reactive losses in the wind farm internal distribution network and reactive losses of the
10kV/110kV step-up transformer, which are not covered by the synchronous generators having a rated power
factor of only 0.9.
Grid Codes
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P1347
140
130
120
Figure 3.3b
Figure 3.3a
Figure 3.3c
Q_WP / pu
110
100
90
underexcited
overexcited
80
-0.8
-0.7
-0.6
-0.5
-0.4
-0.3
-0.2
-0.1
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
Figure 10: Requirements according to [1] and Capability of Wind Farm for Steady-State Reactive Power Support
at P=PN.
In this case two solutions are possible:
•
A generator with high reactive power range (and therefore higher rated apparent power) should be
used. Instead of using a generator with a rated power factor of 0.9, a generator with rated power factor
of 0.85 or even 0.8 should be used for compensating reactive losses in the wind farm internal network
and the 10kV/110kV step-up transformer.
The resulting curve is shown in Figure 11 as a solid violet curve. It can be seen, that all three dashed
curves from [1] are inside the capability curve.
•
An additional capacitor can be added at the main MV bus bar of the wind farm for shifting the complete
reactive capability curve. In this example a 7 Mvar capacitor has been added at the 10 kV substation. The
yellow curve in Figure 11 shows that the wind farm meets all reactive power requirements according to
[1].
Depending on requirements during partial load, the capacitor bank must be switchable with different
steps.
•
Option 1, using a generator with larger reactive power range, will be the more cost effective solution in
most wind farm projects. It is therefore recommended to reconsider the size of the standard generator
and possible go towards a generator with larger MVA rating, at least for projects with HV connection
point.
Grid Codes
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P1347
140
130
120
Figure 3.3b
Figure 3.3a
Figure 3.3c
Q_W P / pu
Q_(pf=0.85) / pu
Q_W P_Cap / pu
110
100
90
underexcited
-0.8
-0.7
-0.6
-0.5
-0.4 -0.3
overexcited
-0.2
80
-0.1
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
Figure 11: Requirements and Capability of Wind Farm for Steady-State Reactive Power Support.
5.3 Behaviour during Disturbances in the Network
The grid code is dividing the generating units using renewable energy sources into two types:
•
Type 1: a synchronous generator directly connected to the network.
•
Type 2: any other generator technology.
The turbine using the Voith WinDrive technology is applying a synchronous generator directly coupled to the
network. Thus for analysing the behaviour of the wind farm after disturbances, the requirements for generators
of type 1 has to be applied. These requirements are listed under section 3.3.12 in [1].
5.3.1 Transient Stability after ShortShort-Circuits
Circuits (section 3.3.13.5 resp. 3.3.12.1 in [1])
Most grid codes require that generators stay connected in the case of network faults (low-voltage ride-through
capability, LVRT). It is of particular importance to transmission system operators, that wind farms stay connected
in case of faults at major transmission levels leading to a voltage depression in a wide area, which could lead to a
major loss of wind generation if wind farms were not equipped with LVRT-capability. Therefore, LVRT-capability is
a definite requirement for all larger wind farms.
The main issue of synchronous generators with direct grid connection (without power electronics converters) is
their ability to remain in synchronism during and after major voltage sags. The corresponding effect is named
“Transient Stability” in literature. The main parameters influencing transient stability are:
Grid Codes
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P1347
•
Rotor inertia/turbine power during the fault.
•
Depth of the voltage sag.
•
Duration of the voltage sag.
•
Short circuit impedance of the grid to which the generators are connected.
The transmission code requires LVRT for two different types of faults at the PCC:
•
Solid 3-phase short-circuit with 150ms clearing time (0% remaining voltage)
•
3-phase short-circuit for 5s with large fault impedance (85% remaining voltage)
According to the requirements a SCR of 6 should be analysed. To assess transient stability of the turbines more
thoroughly and to get a better overview of the performance of the generator concept, simulations are carried out
for three different short-circuit levels at the 110kV connection point (PCC):
•
Strong network:
SCR=20
•
Weak network:
SCR=6
•
Very weak network:
SCR=4
All results of the transient simulations are shown in Annex 3. Table 9 summarizes the results.
Table 9: Results from the Simulations for the Transient Stability according to [1]
Fault
Strong Network
(SCR=20)
Weak Network
(SCR=6)
Very Weak
Network (SCR=4)
3ph Short-Circuit, 0%
stable
stable
stable
stable
stable
stable
The simulations show that the wind generators are stable for all combination of faults and short-circuit levels
analysed. Even at very weak networks with a SCR of 4, the generators are remaining in synchronism after the
short-circuit. Thus in all cases the transient stability of the wind generators is ensured.
As shown in a previous study, the layout of the wind farm grid has a substantial influence on the impedances
between generator and PCC and hence on the stability of the generators. For this layout the minimum short
circuit level is Sk”=180 MVA or a SCR=3.6 for a solid three-phase fault.
5.3.2 Oscillatory Stability (section 3.3.12.2 in [1])
After large disturbances or also after minor network disturbances as they are always present, such as changes in
the voltage due to switching of lines or other network components or load changes, oscillations between the wind
farm and the main network or oscillations between the different generators within the farm can be excited. This
can already be seen in the simulation from the last section “transient stability”. Especially for the very weak
network with SCR of 4 and the three-phase fault with remaining voltage of 85%, an oscillation of around 4-5 Hz
can be seen, which is damped out within 10 s.
Grid Codes
-25-
P1347
The effect of these oscillatory modes and their damping can be analyzed using eigenvalue analysis. Using this
analysis technique characteristic modes of a system are obtained in terms of damping and characteristic
frequency.
The behaviour of the generators and thus the damping of possible modes is depending on the operation point of
the generator. [1] requires the analysis of modes in all possible operation points of the generator within its
capability diagram. Thus for each combination of short-circuit level at the PCC (SCR=20, SCR=6, SCR=4),
different operating points of the generators are investigated:
•
Operation Point 1:
P=PN,
Q=0 Mvar (at PCC)
•
Operation Point 2:
P=PN,
Q=Qmax
•
Operation Point 3:
P=0 MW,
Q=Qmax
•
Operation Point 4:
P=0 MW,
Q=Qmin
•
Operation Point 5:
P=PN,
Q=Qmin
Frequency and damping of each mode is calculated and analyzed. The results of the calculations are visualized in
Annex 3 in form of eigenvalue plots containing eigenvalues in the complex plane. Additionally the participation
factors are shown for two eigenvalues with the lowest damping. The results for these eigenvalues from the
eigenvalue analysis are summarized in Table 10 to Table 12 for all short-circuit levels at the PCC.
Table 10: Results of the Eigenvalue Analysis for SCR=20
SCR=20
P=PN, Q=0 Mvar
P=PN, Q=Qmax
P=0MW, Q=Qmax
Mode No.
Period
Frequency
s
Hz
Damping
Ratio
Mode 00576
0.183
5.47
2.750
1.654
Mode 00578
0.171
5.84
4.526
2.171
A1/A2
Mode 00576
0.184
5.44
2.796
1.672
Mode 00578
0.174
5.76
4.568
2.212
Mode 00507
0.190
5.27
1.539
1.339
Mode 00509
0.186
5.38
2.796
1.681
P=0MW, Q=Qmin
Mode 00452
0.198
5.04
1.841
1.441
Mode 00454
0.200
5.01
2.139
1.533
P=PN, Q=Qmin
Mode 00578
0.161
6.20
4.103
1.937
Mode 00626
0.178
5.62
2.406
1.535
Grid Codes
-26-
P1347
SCR=6
Mode No.
P=PN, Q=0 Mvar
P=PN, Q=Qmax
P=0MW, Q=Qmax
Period
Frequency
s
Hz
Damping
Ratio
Mode 00575
0.171
5.84
4.524
2.171
Mode 00583
0.189
5.29
2.286
1.541
A1/A2
Mode 00573
0.190
5.26
2.303
1.549
Mode 00575
0.174
5.75
4.567
2.211
Mode 00494
0.193
5.18
1.014
1.216
Mode 00496
0.186
5.38
2.796
1.681
P=0MW, Q=Qmin
Mode 00454
0.198
5.05
1.564
1.363
Mode 00486
0.200
5.01
2.139
1.533
P=PN, Q=Qmin
Mode 00624
0.186
5.38
2.044
1.462
Mode 00575
0.161
6.20
4.100
1.937
Damping
Ratio
SCR=4
P=PN, Q=0 Mvar
P=PN, Q=Qmax
P=0MW, Q=Qmax
P=0MW, Q=Qmin
P=PN, Q=Qmin
Mode No.
Period
Frequency
s
Hz
Mode 00574
0.171
5.84
4.524
2.171
Mode 00622
0.192
5.21
2.155
1.513
Mode 00572
0.193
5.17
2.167
1.520
Mode 00574
0.174
5.75
4.566
2.211
Mode 00494
0.195
5.12
0.810
1.171
Mode 00496
0.186
5.38
2.796
1.681
A1/A2
Mode 00453
0.198
5.05
1.416
1.324
Mode 00486
0.200
5.01
2.139
1.533
Mode 00575
0.161
6.20
4.100
1.937
Mode 00624
0.186
5.38
2.044
1.462
From the eigenvalue diagrams in Annex 3 it can be derived, that there are oscillatory modes in different
frequency ranges:
•
around 2.6Hz
inherent mechanical mode of the drive train and low damping,
no participation of generators.
•
2.4-3.3 Hz
local wind farm modes representing oscillations of combined generator/turbine
inertias within the wind farm and of the wind farm against the network.
•
5-7 Hz
oscillations related to generator inertia within the wind farm and of the wind farm
against the network.
•
30-33 Hz
torsional modes of the drive trains.
•
45-46 Hz
torsional modes of the drive trains.
Grid Codes
-27-
P1347
These results are similar to the results derived in the previous study. An additional torsional mode at 45 Hz is
occurring, due to the more complex drive train model.
The modes at around 2.4..3.3 Hz are oscillations related to the combined inertia of generator and turbine. The
mode with lowest damping indicates the oscillation between the wind farm and the network. The local wind farm
modes representing oscillations between generators and groups of generators show higher damping. Generally all
modes are very well damped.
The lowest damped mode at around 5 Hz represents oscillations of the wind farm against the external 110 kV
network (first mode listed in Table 10 to Table 12). These oscillations show a good damping even at low short
circuit levels at the PCC, where the ratio between consecutive swings is around 1.1 to 1.4. The minimum is
reached at low power output (low wind conditions) and at weak PCCs, although the damping is still sufficient.
The other modes in the frequency range between 5..7 Hz are related to generator oscillations within the wind
farm, i.e. groups of generators or strands oscillating against each other. These modes are better damped then
the “wind farm mode” described above. The mode with the lowest damping is the second mode listed in Table 10
to Table 12. Annex 3 also shows the participation phasor diagrams for both modes. Here it can be seen, that the
generators are oscillating against the network resp. against each other.
Oscillatory modes at higher frequencies are torsional modes of the drive trains. These oscillations are always
present in case of wind turbines. However, they are not causing any interactions between the wind generators
and are therefore not critical.
Additionally it can be concluded that oscillatory modes around frequencies of 0.5 – 1 Hz are not present, thus
periodically excited frequencies in this range, like the tower shadow effect, will not result in persisting oscillations.
Grid Codes
-28-
P1347
6 Requirements
Requirements for Connections to the Distribution (MV) Grid
For the connection of power plants and wind generators to the German distribution grid at medium voltage level,
the German grid code “Mittelspannungsrichtlinie 2008” [2] published by the BDEW - Bundesverband der Energieund Wasserwirtschaft e. V. defines the technical requirements.
In this chapter the different requirements are analysed and the compatibility of the wind turbine concept using a
hydro-dynamically controlled gearbox (WinDrive) is investigated. The corresponding calculations and simulations
are described and the results are shown.
Here a wind farm with 10 x 2 MW wind generators is connected to the distribution network at 10 kV voltage level.
The generators are assumed to operate at full power output in all calculations. The wind turbine is modelled in
detail, as described in section 2. A step-up transformer for the wind generator is not needed when connected
directly to the 10 kV voltage level.
For the simulations three different values for the short-circuit level at the point of common coupling (PCC) have
been assumed. These values are chosen to be typical values for strong and weak MV networks:
•
Strong network:
Sk’’=500 MVA
SCR=25
•
Weak network:
Sk’’=250 MVA
SCR=12.5
•
Very weak network:
Sk’’=150 MVA
SCR=7.5
For all listed short circuit levels at the PCC, the following stability aspects have to be analysed according to the
“Mittelspannungsrichtlinie 2008” [2]:
Network Disturbances (section 2.4):
•
Steady-state voltage changes.
•
Transient voltage changes due to switching.
•
Flicker.
•
Harmonics.
•
Commutation voltage drops.
•
Impact on ripple control.
Behaviour of the Generator (section 2.5):
•
Transient stability of the wind farm (behaviour during large disturbances).
•
Short-circuit current.
•
Active power output.
•
Reactive power output.
Grid Codes
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P1347
6.1 Network Disturbances
6.1.1 SteadySteady-State
State Voltage Changes (Section 2.3 in [2])
The steady-state voltage change is depending on the layout of the medium voltage network, the strength of the
network (short-circuit level) and the point in the network, where the wind farm is interconnected. Also the
steady-state voltage change is not depending on the generator technology but only on the rated power of the
power plant.
Thus this issue has to be analysed for each individual wind farm project and can not investigated in combination
with a simplified network equivalent.
6.1.2 Voltage Change due to Switching Operations (section 2.4.1 in [2])
Due to connection and disconnection of wind generators the maximum voltage change shall not exceed the limit
of 2%. Compared to asynchronous generators, which might use a direct start-up method having a large impact
on network voltage, the direct coupled synchronous generator uses an offline start-up method and
synchronisation devices. Thus the analysed wind turbine concept will only have a minor impact on system voltage
during switching operations.
According to [2] a simple way of estimate the maximum voltage step change is to use an approximated value
kimax, which is defined as the maximum switching current rated to nominal generator current. For synchronous
machines this factor can be assumed to be kimax=1.2. The voltage step change can then be calculated
∆u max = k i max
S rE
1
= k i max
< 2% ,
S kV
nGen ⋅ SCR ⋅ cos(ϕ r )
where nGen is the number of generators in the wind farm and cos(ϕr) is the rated power factor.
It can then be estimated that for wind farm with 10 turbines with 2 MW each connected to a weak network with
a SCR of 10, the ∆umax is then 1.33 % and thus below the maximum of 2 %.
A more exact method to assess the impact of switching operations on the voltage is to use the maximum “voltage
change factor” kU(ψK) and the “flicker step factor” kf(ψK), which measured at different network impedance angle
and at cut-in and rated wind speed. The values are provided in the data sheet of the turbine.
The maximum voltage change ∆umax is calculated as follows:
∆u max = kU (ψ K )
S rE
1
= kU (ψ K )
< 2%
S kV
Thus the voltage change factor for nGen=10 generators in the wind farm and rated wind speed as well as cut-in
wind speed is derived and shown in Table 13 and Table 14.
Grid Codes
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P1347
Table 13: Voltage Change Factor and max. Voltage Change ∆umax for different SCR Values and
Impedance Angles for 10 Generators and at rated Wind Speed.
∆umax / %
ψK=30°
ψK=50°
ψK=70°
ψK=85°
Voltage change factor
1.03
0.74
0.38
0.14
25
0.458
0.329
0.169
0.062
12.5
0.916
0.658
0.338
0.124
7.5
1.526
1.096
0.563
0.207
Table 14: Voltage Change Factor and max. Voltage Change ∆umax for different SCR Values and
Impedance Angles for 10 Generators and at cut-in Wind Speed.
∆umax / %
ψK=30°
ψK=50°
ψK=70°
ψK=85°
Voltage change factor
0.21
0.14
0.06
0.04
25
0.093
0.062
0.027
0.018
12.5
0.187
0.124
0.053
0.036
7.5
0.311
0.207
0.089
0.059
It can be seen that in all cases the limit of 2% is not exceeded, when the wind generators are switching at rated
or cut-in wind speed for realistic values of short-circuit ratios in the 10 kV network.
Additionally the data sheet provides a value for the maximum “flicker step factor” kf(ψK), which is also caused by
switching operations and is again depending on the network impedance angle. The long-term flicker limit Plt,max of
0.46 should not be exceeded by this effect. Plt can be calculated from the flicker step factor and the number of
switching operations within 120 min in the following way, if all turbines are of the same type:
nGen
8 
Plt =
N120,i ⋅ k f ,i (ψ K ) ⋅ S rE
S kV  i =1
∑
(
)
3.2




0.31
= 8 ⋅ (nGen ⋅ N120 )0.31 ⋅ k f (ψ K ) ⋅
S rE
< 0.46
S kV
Thus the maximum number of switching operation N120 are:
N120 =
1
nGen


S
1

⋅  Plt ,max ⋅ kV ⋅


S
8
⋅
k
(
ψ
)
rE
f
K


1
0.31
=
1
nGen


1

⋅  Plt ,max ⋅ ( SCR ⋅ nGen ⋅ cos(ϕ r )) ⋅


8
⋅
k
(
ψ
)
f
K


1
0.31
According to the IEC 61400-21 standard [4] the value N120 is provided by the manufacturer. If not given, it can
be assumed to be 120 at cut-in wind speed and 12 for rated wind speed, indicating an estimated 120 resp. 12
switching operations in 120 min.
The tables below show the maximum value for N120, for which the limit of Plt = 0.46 is not exceeded. These
values are then compared to minimum numbers for N120. of 120 at cut-in wind speed and 12 for rated wind
speed.
Grid Codes
-31-
P1347
Table 15: Maximum Switching Operations within 120 min for different SCR Values and Impedance
Angles for 10 Generators and at rated Wind Speed.
N120
ψK=30°
ψK=50°
ψK=70°
ψK=85°
Flicker step change
0.25
0.18
0.11
0.08
25
33786
97490
477415
1333624
12.5
3611
10421
51031
142551
7.5
695
2006
9822
27436
Table 16: Maximum Switching Operations within 120 min for different SCR Values and Impedance
Angles for 10 Generators and at cut-in Wind Speed.
N120
ψK=30°
ψK=50°
ψK=70°
ψK=85°
Flicker step change
0.21
0.14
0.06
0.04
25
59293
219301
3373352
12476649
12.5
6338
23441
360576
1333624
7.5
1220
4512
69399
256680
The results show that for all SCR values there is practically no limit for the number of switching operations due to
very low flicker step factors of the generator.
6.1.3 LongLong-Term Flicker (Section 2.4.2 in [2])
Changes in wind speed or turbulences as well as effects like tower shadow can have an impact on the active
power output of the wind generators. This in turn will affect the voltage and can cause voltage variations, which
can disturb other customers connected to the MV network. Therefore the long-term voltage flicker Plt is calculated
to assess the impact on the network.
The data sheet provides a value for the maximum “flicker coefficient” c depending on the network impedance
angle for values of 30°, 50°, 70° and 85° at a different wind speeds. The long-term flicker value can be
calculated as follows:
Plt = nGen ⋅ c ⋅
S rE
1
= c⋅
< 0.46
S kV
Thus the flicker value Plt for nGen=10 generators and for the worst case of a wind speed of 10 m/s in the wind
farm is calculated. The results are shown in Table 17.
Table 17: Long-Term Flicker Value Plt for different SCR Values and Impedance Angles and at rated
Wind Speed for 10 Generators.
SCR
ψK=30°
ψK=50°
ψK=70°
ψK=85°
Flicker coefficient
3.98
3.47
2.81
2.21
25
0.056
0.049
0.039
0.031
12.5
0.112
0.098
0.079
0.062
7.5
0.186
0.163
0.132
0.104
It can be seen that for all cases and even at very weak PCC, the long term flicker Plt is with a maximum of 0.186
far below the limit of 0.46.
Grid Codes
-32-
P1347
6.1.4 Harmonics (Section 2.4.3 in [2])
According to the data sheet the harmonic currents Ih are given in % based on the rated generator current for one
machine. These values are compared to the limits given in [2]. These limits are given in A/MVA. The current
values can then be calculated for one turbine:
Iν ,lim = iν ,lim ⋅ S kV = iν ,lim ⋅ ( Pr ⋅ SCR )
Table 18 shows the measured harmonic currents Ih as well as the harmonic current limit for different SCR values
up to the 50th harmonic order. Red values are indicating a violation of the limits.
It can be seen that for the 5th and 31st harmonic, the current limits are slightly exceeded for very weak networks.
As the distorted currents in the data sheet are derived from preliminary measurements, where large power
electronic devices are connected within the vicinity of the turbine (DFIG and full converter wind turbine in
Cuxhaven), these measurements should be validated first to draw conclusions from these results. Usually
synchronous generators have a very low contribution to harmonic currents in the network, esp. at low
frequencies as the 5th harmonics.
Table 18: Measured Harmonic Currents Ih and Harmonic Current Limits for different SCR Values
Harmonic
Order
Measured
Ih/Ir / %
Measured
Ih / A
ih,max / A/MVA
acc. to [2]
Ih,max / A for
SCR=25
Ih,max / A for
SCR=12.5
Ih,max / A for
SCR=7.5
2.00
0.100
0.128
0.030
1.500
0.750
0.450
3.00
0.300
0.385
0.058
2.900
1.450
0.870
4.00
0.000
0.000
0.015
0.750
0.375
0.225
5.00
1.300
1.668
0.058
2.900
1.450
0.870
6.00
0.000
0.000
0.010
0.500
0.250
0.150
7.00
0.500
0.641
0.082
4.100
2.050
1.230
8.00
0.000
0.000
0.008
0.375
0.188
0.113
9.00
0.000
0.000
0.052
2.600
1.300
0.780
10.00
0.000
0.000
0.006
0.300
0.150
0.090
11.00
0.300
0.385
0.052
2.600
1.300
0.780
12.00
0.000
0.000
0.005
0.250
0.125
0.075
13.00
0.200
0.257
0.038
1.900
0.950
0.570
14.00
0.000
0.000
0.004
0.214
0.107
0.064
15.00
0.000
0.000
0.022
1.100
0.550
0.330
16.00
0.000
0.000
0.004
0.188
0.094
0.056
17.00
0.000
0.000
0.022
1.100
0.550
0.330
18.00
0.000
0.000
0.003
0.167
0.083
0.050
19.00
0.000
0.000
0.018
0.900
0.450
0.270
20.00
0.000
0.000
0.003
0.150
0.075
0.045
21.00
0.000
0.000
0.012
0.600
0.300
0.180
22.00
0.000
0.000
0.003
0.136
0.068
0.041
23.00
0.000
0.000
0.012
0.600
0.300
0.180
24.00
0.000
0.000
0.003
0.125
0.063
0.038
25.00
0.000
0.000
0.010
0.500
0.250
0.150
Grid Codes
-33-
P1347
Harmonic
Order
Measured
Ih/Ir / %
Measured
Ih / A
ih,max / A/MVA
acc. to [2]
Ih,max / A for
SCR=20
Ih,max / A for
SCR=6
Ih,max / A for
SCR=4
26.00
0.000
0.000
0.002
0.115
0.058
0.035
27.00
0.000
0.000
0.009
0.463
0.231
0.139
28.00
0.000
0.000
0.002
0.107
0.054
0.032
29.00
0.000
0.000
0.009
0.431
0.216
0.129
30.00
0.000
0.000
0.002
0.100
0.050
0.030
31.00
0.100
0.128
0.008
0.403
0.202
0.121
32.00
0.000
0.000
0.002
0.094
0.047
0.028
33.00
0.000
0.000
0.008
0.379
0.189
0.114
34.00
0.000
0.000
0.002
0.088
0.044
0.026
35.00
0.000
0.000
0.007
0.357
0.179
0.107
36.00
0.000
0.000
0.002
0.083
0.042
0.025
37.00
0.000
0.000
0.007
0.338
0.169
0.101
38.00
0.000
0.000
0.002
0.079
0.039
0.024
39.00
0.000
0.000
0.006
0.321
0.160
0.096
40.00
0.000
0.000
0.002
0.075
0.038
0.023
41.00
0.000
0.000
0.004
0.220
0.110
0.066
42.00
0.000
0.000
0.001
0.071
0.036
0.021
43.00
0.000
0.000
0.004
0.209
0.105
0.063
44.00
0.000
0.000
0.001
0.068
0.034
0.020
45.00
0.000
0.000
0.004
0.200
0.100
0.060
46.00
0.000
0.000
0.001
0.065
0.033
0.020
47.00
0.000
0.000
0.004
0.191
0.096
0.057
48.00
0.000
0.000
0.001
0.063
0.031
0.019
49.00
0.000
0.000
0.004
0.184
0.092
0.055
50.00
0.000
0.000
0.001
0.060
0.030
0.018
6.1.5 Commutation Voltage Drops (Section
(Section 2.4.4 in [2])
This issue is only applicable for gird commutated converters and is not valid for the Voith wind generator concept.
6.1.6 Impact on Ripple Control (Section 2.4.5 in [2])
Synchronous generators can generally have in impact on ripple control systems by lowering the network
impedance. This can lead to higher required ratings of ripple control systems based on parallel infeed and to
lower ripple control signals in case of system with serial infeed.
Grid Codes
-34-
P1347
6.2 Behaviour of the Generator
6.2.1 Transient Network Support
Support – LowLow-Voltage RideRide-Through (Section 2.5.1.2 in [2])
Similar to the requirements for wind farm connections to the HV network, the “Mittelspannungsrichtlinie 2008”
requires a power plant to be able to:
•
Stay connected in the case of network faults (Low-voltage ride-through capability (LVRT) or fault ride
through capability (FRT)).
•
Provide reactive current during the fault.
•
Have limited reactive power consumption after the fault.
The voltage profile according to the grid code is valid for synchronous generators, which are directly connected to
the network (type 1 generators). These are obliged to stay connected during typical network faults that show
voltage profiles at the PCC that are contained in voltage shaped shown in Figure 12 [2].
The main issue of synchronous generators with direct grid connection (without power electronics converters) is
their ability to remain in synchronism during and after major voltage sags. The corresponding effect is named
Transient Stability in literature.
Figure 12: Requirements for Low Voltage Ride Through Capability of Generators according to [2].
Grid Codes
-35-
P1347
For three different short-circuit ratios (SCR) at the PCC different short-circuits short-circuits have been calculated
to analyse extreme cases of faults according to Figure 12. These short-circuits are:
•
Solid 3-phase short-circuit with 150ms clearing time (0% remaining voltage)
•
3-phase short-circuit for 700ms with 70% remaining voltage
•
Voltage Step at PCC to 90%
The detailed results of the simulation are shown in Annex 4. Table 19 summarizes the results.
Table 19: Results from the Simulations for Transient Stability
Fault
Strong Network
(SCR=25)
Weak Network
(SCR=12.5)
Very Weak Network
(SCR=7.5)
stable
stable
stable
stable
stable
stable
Voltage Step, 90%
stable
stable
stable
The results show, that the generators do not face instability in any case.
The behaviour is also dependent on the actual layout of the farm grid. If for example a step-up transformer or a
cable is connected in between generator and grid, the total impedance between generator and network is
increase, which will have a negative effect on the stability of the wind farm. On the other hand the generator
provides a high amount of reactive power during voltage depression. This voltage support has a positive effect on
the terminal voltage and thus on the generator stability. Thus the individual wind farm layout has to be tested for
each project.
All power plants are required to provide a reactive current during the fault. As shown in the simulations in
Annex 4, the synchronous generators contribute up to 8 times its rated current as reactive current to the network
during the solid 3-phase fault. Thus the voltage can be very well supported in the neighbouring MV network.
6.2.2 ShortShort-Circuit Current (Section 2.5.2 in [2])
A synchronous generator will provide relatively high short-circuit currents to the network compared to other wind
generator technologies. Thus it has to be ensured, that the ratings of the switchgear in the connected network is
not exceeded by the additional short-circuit contribution of the wind farm.
This issue is depending on the design of the medium voltage network and the individual substations. Thus it has
to be analysed for each individual wind farm project and can not investigated in combination with a simplified
network equivalent.
6.2.3 Active Power Output (Section 2.5.3 in [2])
These requirements are identical to the ones described in the TransmissionCode 2007. These are analysed in
detail in the previous chapter.
Grid Codes
-36-
P1347
6.2.4 Reactive Power Output (Section 2.5.4 in [2])
In contrast to the reactive power capability curves at the PCC shown in the TransmissionCode 2007 [1], the
requirements are that the generator should be able to operate at a power factor between 0.95 (overexcited) and
0.95 (underexcited) for the complete active power range.
According to the capability diagram of the generator used for the Voith wind turbine, the machine is able to
operate between a power factor of 0.9 (overexcited) and 0.9 (underexcited) at the nominal operation point at
P=PN and increased reactive power output at partial and no load conditions (see also Table 3). Load-flows for
four operation points show the reactive capability at the wind farm PCC.
Table 20 and Figure 13 show the resulting power factor and reactive power output at the PCC of the wind farm.
It can be seen that the wind farm is able to operate at a power factor down to 0.9 for overexcited and
underexcited operation. For reduced active power output the reactive power output can be increased and thus
the generator can operate at lower power factor values. Also if taking reactive power losses in the wind farm
network into account, the required power factor can be easily maintained.
Table 20: Reactive Power Limits and Power Factor of Wind Generator at P=0MW and P=PN
Pgen / MW
Qgen_max / Mvar
required cos(ϕ
ϕ)
cos(ϕ
ϕ)
0.00
0.710
0.95 (overexcited)
0 (overexcited)
0.00
-0.580
0.95 (underexcited)
0 (underexcited)
2.00
0.436
0.95 (overexcited)
0.906 (overexcited)
2.00
-0.436
0.95 (underexcited)
0.886 (underexcited)
1.2
P / pu
1
0.8
Q(pf=0.95) / pu
Q_WP / pu
0.6
0.4
0.2
underexcited
-1.000
-0.800
-0.600
-0.400
-0.200
overexcited
0
0.000
0.200
0.400
0.600
0.800
1.000
Figure 13: Capability of Wind Farm for Steady-State Reactive Power Support at the PCC and required Reactive
Power Output in p.u. based on Nominal Active Power PN.
Grid Codes
-37-
P1347
Additionally the wind farm should be able to change its reactive power output from the maximum to the
mimimum steady-state requirements within a given time. Thus the power factor has to be able to control from
0.95 (overexcited) to 0.95 (underexcited) or vice versa within 10 s. To show this a dynamic simulation has been
performed, where the voltage setpoint of the voltage controllers of the wind generators is changed at 0 s in a
way that the reactive power output at the PCC changes from +6.5 Mvar to -6.5 Mvar.
Annex 4.4 shows the simulation results. It can be seen that the response of the wind farm is fast and the
required change in reactive power output can be carried out at least within 6-7 s.
The behaviour of the wind farm to voltage changes can be seen also in the simulations to the transient stability.
Here a voltage step to 90% nominal voltage at the PCC shows a very fast increase of reactive power output of
the wind farm within 1-2 s.
Grid Codes
-38-
P1347
7 Conclusion
In this study the steady-state and dynamic behaviour of the Voith wind turbine concept with variable speed
gearbox and directly grid-coupled synchronous generator is analysed. The main focus is the compatibility of the
performance of typical wind farms with regard to the technical requirements derived from the German grid codes:
•
the “TransmissionCode 2007” for connections to the transmission (HV) systems and
•
the “Mittelspannungsrichtlinie 2008” for connections to the distribution (MV) systems.
The requirements of the “TransmissionCode 2007” concerning reactive power output at the point of common
coupling (PCC) can all be met.
Transient stability has been investigated for different short-circuit ratios (SCR) at the PCC. Low-voltage ridethrough and high reactive current support to the network can be ensured in all cases, when connected to very
weak networks. Eigenvalue analysis has shown that oscillatory stability is no issue at any SCR value or any
operation point of the generator, thus even at low power output the generators will provide sufficient damping of
modes for modes within the frequency range of 5-7 Hz.
For connections of a wind farm to the medium-voltage network at 10 kV the different regulations according to the
“Mittelspannungsrichtlinie 2008” have been analysed. It is shown that all requirements are met and all limiting
factors are well complied with, when the farm is connected to a sufficiently strong PCC. Also the specifications
regarding low-voltage ride-through and reactive power support can be exceeded.
Only the harmonic currents injected into the network are slightly exceeding the given limits at two frequencies.
Because it is very much unlikely that a generator concept with directly grid-coupled synchronous generators
causes any kind of harmonic problem, the harmonic current measurements should be verified before drawing any
further conclusions.
Grid Codes
-39-
P1347
8 References
[1]
TransmissionCode 2007, Netz- und Systemregeln der deutschen Übertragungsnetzbetreiber, Version 1.1,
Verband der Netzbetreiber –VDN- e.V. beim VDEW, August 2007.
[2]
Technische Richtlinie, Erzeugungsanlagen am Mittelspannungsnetz, BDEW Bundesverband der Energieund Wasserwirtschaft e.V., Juni 2008.
[3]
Power Cables and their Application – Part 2, L. Reinhold, R Stubbe, 3rd rev. edition, Siemens AG, 1993.
[4]
IEC 61400-21, International Standard, Edition 12-2001, Wind turbine generator systems, Part 21:
Measurement and assessment of power quality characteristics of grid connected wind turbines,
December 2001.
Grid Codes
-40-

Grid Compatibility of Wind Generators with Hdyro

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