Download Damping Of Power System Oscillations by VSC

Damping Of Power System Oscillations
by VSC-HVDC Multi-Terminal
Transmission Networks
Authors: Mario Ndreko, Arjen van der Meer, Barry Rawn,
Madeleine Gibescu
WP 6.1. NSTG Project Technical Report, Part I
06/11/2012-08/03/2013
Revised: April 26, 2013
Status: Confidential
ESE-IEPG
Delft University of Technology
1 2 Introduction
Small-signal instability refers to poorly damped oscillations arising in physical
systems when subjected to small disturbances and can usually be quantified with an
eigenvalue analysis of the linearized system model. In power systems, critical
damping levels related to inter-area oscillations usually occur when two network areas
in one synchronous system are connected by electrically weak lines. With the growth
of interconnected power systems, small-signal stability has been receiving increasing
attention. In a deregulated environment, increasing international power exchanges
lead to higher loading of the transmission system. Additional flows in new directions
and lowered system inertia are a result of increased penetration of wind and other
RES. Transmission system operators are faced with the prospect of operating the
system close to its stability limits, or if this is not acceptable, then preventive
measures such as security-constrained re-dispatch while limiting power transfers may
be the outcome. This results in deviations from the unconstrained market equilibrium.
Low-frequency inter-area oscillations have been observed in all three synchronous
systems bordering the North Sea: the UK system, the Nordic interconnection, and the
Continental (former UCTE) system. Recordings of the Wide Area Measuring System
(WAMS) have shown poorly damped low-frequency power oscillations in the
Continental European System [1]. Thus, there is definitely concern in damping both
local and inter-area oscillations in all systems surrounding the North Sea. When this
problem is dealt with adequately, market operation can proceed optimally, without
unnecessary curtailment of power transfers to lower levels.
Improved inter-area oscillation damping has been treated as a linear control problem,
with many research papers and practical applications focusing on ways to modulate
the power or voltage reference set-points of synchronous generators and HVDC
converters. This report adds to the existing body of work by investigating the ability
of a multi-terminal offshore VSC-HVDC transmission network to damp onshore
power oscillations. Power oscillation damping (POD) controllers which act at the grid
side converter stations of a multi-terminal dc (MTdc) network will be discussed. The
involvement of offshore wind farms to provide this damping energy from within the
MTdc network is also discussed. It is shown that the proposed control structures can
induce damping of local and inter-area modes in a chosen onshore power system by
proper active power modulation at the ac terminal, while also – when carefully tuned
– avoiding the transmission of that modulation to other onshore power systems. The
possible limitations on such a control scheme imposed by a more realistic wind
turbine model are also examined.
The report is divided into four sections. Section 1 discusses the state-of-the-art
methods for realizing the damping of power system oscillations. A proposal for
controllers operating at the grid-side VSC (GSVSC) of the MTdc network is given.
3 The performance of the MTdc network will be validated with a test system in Section
2 and conclusions will be drawn about the interaction of the POD with the direct
voltage controllers. The potential for wind farms to contribute to the provision of
damping energy by coordination with the POD function at the GSVSC is introduced,
and examined more closely in Section 3. Finally, in Section 4, a realistic case study
using publicly-available data for the UK and Nordic power system equivalent models
is considered. The two models are coupled with a hypothetical MTdc network. Time
domain simulations will be shown and conclusions will be drawn about the ability of
the proposed controller to improve the damping of the UK system 0.5 Hz inter-area
mode without jeopardizing the stable operation of the MTdc network and that of the
Nordic power system.
4 Table of Contents
Introduction ........................................................................................................................... 3
List of Symbols ..................................................................................................................... 6
List of Acronyms................................................................................................................... 7
List of Figures ....................................................................................................................... 8
1 Common methods of damping power system oscillations ............................................... 10
1.2 Utilization of VSC-HVDC technology for damping power system oscillations........... 11
1.3 Application of POD controllers in VSC-based HVDC systems connected to a MTdc
offshore network.................................................................................................................. 12
1.3.1 PSS-type POD ........................................................................................................ 13
1.3.2 Simple proportional POD controller....................................................................... 14
2 POD controller validation with a simple test system ....................................................... 15
2.1 Model of VSC-Based MTdc transmission network .................................................. 17
2.2 Case study.................................................................................................................. 18
2.3 Simulation Results..................................................................................................... 19
3. Examination of wind turbine limitations imposed on POD contribution of OWP.......... 26
4 A case study of UK equivalent model coupled with the Nordic power system via a multiterminal VSC-HVDC offshore network .............................................................................. 29
4.1 Nordic power system model...................................................................................... 29
4.2 UK power system model ........................................................................................... 30
4.3 Simulation results ...................................................................................................... 31
5 Conclusions and discussion.............................................................................................. 43
References ............................................................................................................................... 44
Appendix A ............................................................................................................................. 46
Appendix B.............................................................................................................................. 47
Appendix C.............................................................................................................................. 48
Appendix D ............................................................................................................................. 49
Appendix E.............................................................................................................................. 49
5 List of Symbols
I pr
Phasor of the phase reactor current
I source
Phasor of the current source of the Norton VSC equivalent model
X pr
Phase reactor reactance installed at the converter station
R pr
Resistance of the equivalent model of the phase reactor
R dc
Resistance of the π-equivalent model of HVDC cable
Ldc
Inductance of the π-equivalent model of HVDC cable
C dc
Capacitor of the π-equivalent model of HVDC cable
I dc
U dc
Dc current injection at terminal of the HVDC cable
Us
iq
Phasor of the AC voltage at the AC grid connection point of the converter station
id
d-axis component of the phase reactor current
U pcc
Phasor of the converter voltage at point of common coupling
Pref
Active power reference of the converter station
Qref
Reactive power reference of the converter station
P
Q
kp
Active power of the converter station
ki
Integral gain of the PI controller
ΔPref
Output signal of the Power oscillation damper controller
ΔPmax
ΔPmin
Upper limiter of the Power Oscillation Damper (POD) controller
Direct voltage at the multi-terminal DC network
q-axis component of the phase reactor current
Reactive power of the converter station
Proportional gain of the PI controller
Lower limiter of the Power Oscillation Damper (POD) controller
Tw
Kdmp
Power Oscillation Damper controller washout block time constant
K pss
Proportional gain of the classic Power System Stabilizer
ΔPowp
Modulated offshore wind park active power
ΔPGSVSC
θs
Proportional gain of the Power Oscillation Damper Controller
Modulated grid side VSC active power
Voltage angle at the AC side connection point of the VSC
6 List of Acronyms
ac
AVR
dc
FRT
GSVSC
HVDC
IGBT
MTdc
NSTG
PCC
PI
PLL
POD
PSS
PWM
VSC
OWPP
WPVSC
Alternative current
Automatic Voltage Regulator
Direct current
Fault Ride Through
Grid side voltage source converter
High Voltage Direct Current
Insulated Gate Bipolar Transistor
Multi-terminal Direct Current
North Sea Transnational Grid
Point of Common Coupling
Proportional Integral controller
Phase Lock Loop
Power Oscillation damper
Power System Stabilizer
Pulse Width Modulation
Voltage Source Converter
Offshore Wind Power Park
Wind Park voltage source converter
7 List of Figures
Figure. 1
Common methods of damping power oscillations in power systems............... 10
Figure. 2
Representation of full system control structure for introducing damping of
electromechanical oscillations [8] ........................................................................................... 11
Figure. 3
Control modes of the grid side converter station a) dc voltage control mode b)
reactive power control mode and c) active power control mode d) ac voltage controller....... 12
Figure. 4
PSS type POD for application in VSC stations ................................................ 13
Figure. 5
Simple proportional POD controller for application in VSC stations .............. 15
Figure. 6
Two asynchronous test Power Systems connected via a MTdc network (the
HVDC cable parameters can be found in Appendix D) ......................................................... 16
Figure. 7
Model of the VSC module ............................................................................... 17
Figure. 8
(a) Coordinated operation of the offshore wind power plant with the GSVSC
POD (b) Active power controller of Type 4 Wind Power Plant [15]...................................... 18
Figure. 9
Active power of generator 3 ............................................................................ 19
Figure. 10
Modulated active power of the GSVSC3 (Sb = 400MVA)............................. 20
Figure. 11
direct voltage at the dc terminal of GSVSC3 .................................................. 21
Figure. 12
Active power of the Offshore wind power plant and GSVSC (Sb = 400MVA)
21
Figure. 13
Direct voltages of the MTdc network when there is NO POD........................ 22
Figure. 14
Direct voltages of the MTdc network with the POD....................................... 22
Figure. 15
Direct voltages of the MTdc network with POD on both OWP2 and GSVSC3
23
Figure. 16
400MVA)
Variation of active power at GSVSC2 as a result of pod at GSVSC3 (Sb =
24
Figure. 17
Variations of active power at GSVSC1 as a result of pod at GSVSC3
(Sb=400MVA)......................................................................................................................... 24
Figure. 18
Variations of active power of Ga at system area 2........................................... 25
Figure. 19
Variations of active power of Gb at system area 2........................................... 25
Figure. 20
Variations of active power of Gc at system area 2........................................... 26
Figure. 21
Excerpt from Danish thesis [25] showing failure to achieve POD commands
above 0.5 Hz. Reference (blue) compared against actual power output at PCC (red) .......... 27
Figure. 22
UK power system connected to the Nordic system by a MTdc grid ............... 29
Figure. 23
Equivalent model of the Nordic power system used in this report [22] .......... 30
Figure. 24
Voltage profile at the busses of the UK power system model for 140ms three
phase symmetrical fault at bus 1007 ....................................................................................... 32
8 Figure. 25
Speed deviations (Δω) of the UK power system generators for 140ms
symmetrical fault at bus 1007.................................................................................................. 33
Figure. 26
Direct voltage variation at the dc nodes of the MTdc offshore network ......... 34
Figure. 27
Active power response from the ac side of the GSVSCs connected to the MTdc
grid (Sb=1000MVA) ............................................................................................................... 34
Figure. 28
in operation
Ac voltage profiles in the UK power system when the POD at GSVSC 1002 is
35
Figure. 29
Power oscillations of selected generators in UK power system with and
without POD at GSVSC of bus 1002 (Sb =1000MVA).......................................................... 36
Figure. 30
G2 speed deviation with and without POD at GSVSC of bus 1002................ 37
Figure. 31
UK power system synchronous generators speed deviations Δω - With POD at
GSVSC of bus 1002 in the UK power system ........................................................................ 37
Figure. 32
UK power system GSVSC - With POD .......................................................... 38
Figure. 33
Direct voltage variations created by the POD of GSVSC at bus 1002 of UK
power system when POD is in operation ................................................................................ 38
Figure. 34
Active Power profiles of GSVSCs in the Nordic system ................................ 39
Figure. 35
Active Power profiles of synchronous generator at bus 5600 (Norway,
Sb=1000MVA)........................................................................................................................ 40
Figure. 36
Active power response of the VSC of the MTdc grid when there is both POD
at GSVSC 1002 and the offshore wind power plant ............................................................... 41
Figure. 37
Direct voltage variations with both POD at GSVSC 1002 and offshore wind
power plants 2 41
Figure. 38
Active Power profiles of synchronous generator at bus 5600 (Norway,
Sb=1000MVA)........................................................................................................................ 42
9 1 Common methods of damping power system oscillations
Power system oscillations appear as a result of disturbances in power systems. They
occur mainly as rotor oscillations of one generator or as oscillations of group of
generators against another group or even oscillations of a whole area against another
area. Power oscillations are related to the equivalent system inertia. In other words, a
disturbance in one power system accelerates (or decelerates) its equivalent inertia
against the equivalent inertia of another system.
Power
Oscillation
Damping
POD using the
turbine-generator
unit
POD in the AC
system
Modulation of
Series
Impedance
Figure. 1
Modulation of
Active Power
Modulation of
Reactive
Power
Application of a
Power System
Stabilizer
PSS
Common methods of damping power oscillations in power systems
Damping of power oscillations can be achieved when extra energy is exchanged with
the power system. The damping energy should have the correct phase shift relative to
the accelerated or decelerated generators. In principle there are two ways to damp
power system oscillations as given in Figure 1. The first includes the application of powers system stabilizers that operate in
conjugation with the excitation system of synchronous generators (right part of the
chart). The main duty of the power system stabilizer is to increase the damping torque
component of the synchronous generator [2]. It is usual to select the power system
stabilizer parameters for a given frequency of electromechanical oscillation, which in
most of the situations is the local mode of the particular generator.
The second way of damping oscillations (left part of the chart) includes methods that
are applied in the transmission system. Such methods are the modulation of line
impedances (by use of Statcoms or other flexible transmission system devices) or
modulation of active (or reactive) power injection at the end of the transmission lines
[3].
10 1.2 Utilization of VSC-HVDC technology for damping power system oscillations
Significant damping of power system oscillations can be achieved when the active
power at the end of transmission lines is modulated, especially in the situation when
the transmission line is interconnecting two areas which oscillate one against the other
[3] [4]. This technique is used and has illustrated significant success in HVDC
transmission systems that operate in parallel to high voltage ac transmission lines.
Particularly, there has been significant research investigating methods for the
improvement of the small signal stability of power systems by utilization of HVDC
lines (both VSC-based and LCC-based) [5] [6] [7].
The main idea is that the modulated active power by the converter stations at the end
of the HVDC lines could accelerate (or decelerate) the local generators contributing a
net damping effect on the power system. In addition, generators in the remote system
are only slightly affected.
Figure. 2
Representation of full system control structure for introducing damping of
electromechanical oscillations [8]
Figure 2 introduces a graphical example of a power system where synchronous
generators and grid side voltage source converter stations are operating
simultaneously. As it can be seen, in order to improve the damping in the power
system, either a PSS could be utilized operating at the synchronous generator
excitation system or a Power Oscillations Damper (POD) controller at the grid side
converter stations, or even both.
The active power of the ac transmission line is commonly used as input signal and
more specifically its time derivative. The main advantage is that the active power can
be measured easily. The disadvantage is that the relation between active power,
flowing through a transmission line, and the voltage angles between the terminals is
non-linear, as given from the equation in Appendix E. Thus, following a disturbance,
if the angle difference between the terminal of the transmission line exceeds 90
degrees, during a disturbance, the sign of the power flow will change and the POD
11 will produce a negative signal. Another approach is to use the derivative of voltage
angle at a generator bus or even the generator speed deviation, in the case that Wide
Area Measurement Systems (WAMS) are available. In most of the applications the
active power derivative of transmission lines is frequently used as an input signal [7].
1.3 Application of POD controllers in VSC-based HVDC systems connected to a
MTdc offshore network
The technique of active power modulation applied in the literature at the terminal of
point-to-point HVDC links can also be used with GSVSCs that operate in multiterminal VSC-HVDC offshore networks. In a VSC-based MTdc network there is, at
least, one or more GSVSC stations responsible for maintaining the direct voltage at its
operational levels [9] [10]. However, it is possible that one or more GSVSCs operate
in active power control mode in order to fulfill a market-dictated power transfer. The
latter converters, next to their ability to transport constant active power under normal
operation, could facilitate a Power Oscillation Damping (POD) controller that
modulates the active power injection of the specific GSVSC station under emergency
or post fault conditions. In this way, the GSVSC can damp low-frequency oscillations
that appear in the ac system.
As mentioned above, GSVSCs need to be in active power control mode in order to
facilitate POD controllers. The main difference between active power and direct
voltage control mode is that in the direct voltage control there is no “direct” active
power order to the converter station to change or vary its active power set point.
Active power injection at the ac side of converter is changed “indirectly” based on the
dc voltage level at the dc capacitor of the converter station. The reader should recall
the different direct voltage control strategies (droop control or voltage margin
method) that can apply various power dispatch schemes [11]. Figure 3 illustrates the
common control modes of the GSVSC.
U dcref
−
kp +
+
ki
s
id
Qref
+
−
U dc
Pref
kp +
P
ki
s
iq
ki
s
iq
Q
+
−
kp +
ki
s
id
U sref
+
kp +
−
Us
Control modes of the grid side converter station a) dc voltage control mode b)
reactive power control mode and c) active power control mode d) ac voltage controller
Figure. 3
12 On the other hand, in active power control mode, the controller is capable to directly
modulate the active power set point of the GSVSC. The latter is important because
these converter stations can improve power system small signal stability by
implementation of a supplementary POD controller.
1.3.1 PSS-type POD
The PSS-type POD (see Figure 4) includes a wash-out block which is responsible to
filter low frequency changes ensuring that the POD will not affect the steady state
operation of the converter station. It includes also (one or more) phase shift blocks
which ensures that the output signal of the POD is out of phase with the input signal
(typically measured power flow on a major tie-line) in order to effectively cancel out
the oscillations. Finally, limiters are included in order to restrict the variations in the
supplementary input signal to the active power controller to acceptable levels.
Δ Pmax
⎛ 1 + sT1 ⎞
⎜
⎟
⎝ 1 + sT 2 ⎠
n
K pss
sTw
1 + sTw
Pline
Δ Pmin
Δ Pref
Pref
K Vpdc +
K iVdc
s
id
P
Figure. 4
Classical PSS type POD for application in VSC stations
The above-mentioned limiter is important because it influences the variations of the
direct voltage at the dc capacitor of the VSC resulting from the active power
modulation. It is worth mentioning that the modulation of active power injection of
the GSVSC by the POD creates dc voltage variations in the whole MTdc network.
The effect of the POD on the dc voltage of the MTdc network will be discussed in the
following paragraphs and simulation results will be given.
The main advantage of a VSC-HVDC POD controller is the capability of the GSVSC
to quickly modulate its active power. Following a disturbance, the synchronous
generator (or group of generators) connected close to the GSVSC station will start to
oscillate against the external network. As a result of these oscillations the POD
controller will be triggered and start to modulate the GSVSC active power to
counteract generator oscillations.
Consequently, when the GSVSC decreases its active power, the load will be supplied,
instantly, from the kinetic energy in the mass of the generator, which will decelerate
its shaft, introducing in such a way a damping effect. This type of controller has
13 advantages not only in terms of design but also because it introduces equivalent
inertia to the system, as it has been mentioned in [12] [13].
1.3.2 Simple proportional POD controller
The classic PSS type POD that has been introduced in Figure 4 has illustrated
sufficient results in terms of damping power system oscillations and has been applied
in a number of publications [3] [13] [5]. However the application of such PSS type
POD needs careful design and parameter selection, especially when used in converter
stations. The main reason is the phase shift that PSS-type POD introduces to the input
signal.
In the case of PSS application on the excitation system of a synchronous generator,
where the input signal is the speed deviation, this phase shift is required in order to
increase the damping torque component of the generator. Actually this is the main
purpose of the PSS, to contribute a phase shift to the generator torque with respect to
speed deviation increasing thus the damping torque component, which had been
reduced by the excitation system operation [2].
However, in the case that the PSS-type POD is applied in GSVSC stations where the
input signal is the active power of a transmission line or even the speed of the nearby
generator there is no actual need for a phase shift. Furthermore, if not carefully tuned
it may contribute damping in wrong phase. In order to tackle this problem
optimization algorithms that use sophisticated methods have been suggested in [3] [4]
for the design of the POD controller. These methods define the optimum parameters
of PSS-type POD for VSC-based applications which contribute maximum damping
without introducing negative impact on the other system modes.
Another solution, originally adopted for the design of power system stabilizers
facilitated in full converter direct drives wind turbines [14] [12], will be proposed in
this project. The proposed controller is introduced in Figure 5. The controller employs
a simple wash-out filter with time constant Tw, so that the power set point is not
affected in steady state. The output is fed directly to the active power controller of the
grid side converter, as illustrated Figure 5.
The operation of the simple type POD controller is based on simple physical
considerations and doesn’t require the design of special lead/lag compensators as in
the PSS type. A typical wash-out time constant of 10-20s can be applied and the only
degree of freedom is Kdmp, which determines the modes shift. Therefore, the POD can
be designed for every application without sophisticated tuning studies simplifying
both the design and its application. The only necessary constrain is the determination
of the specific mode in the system which is both observable and controllable by the
GSVSC.
14 ΔPmax
K dmp
sTw
1 + sTw
Pline
ΔPmin
ΔPref
K Vp dc +
Pref
K iVdc
s
id
P
Figure. 5
Simple proportional POD controller for application in VSC stations
2 POD controller validation with a simple test system
The proposed control method for improving power oscillations will be validated with
the given test system introduced Figure 6. It consists of two asynchronous power
systems (Area 1 and 2) connected via a VSC-Based MTdc network. A GSVSC is
connected at bus 509. The AC network is modeled by positive sequence rms value
models. Each synchronous generator is rated at 400MVA in both areas and modeled
by a 6th order standard IEEE model with standard excitation system (SEXS) and
governor (TGOV1) [15]. All loads are represented as static loads with constant
impedances. All GSVSCs and WPVSCs are rated at 400MVA as well.
Two offshore wind power plants (OWPP) are considered for this test system both
with 400MW rated power. The assumption taken is that the offshore wind power
plants are equipped with full converter direct drive wind turbines. Standard PSS®E
library aggregate dynamic model of type 4 wind turbine is used in order to model the
offshore wind power plants [15].
Table 1 introduces the selected unit commitment scheme or else known as snapshot
for the test system of Figure 6. More specifically for the present case study,
GSVSC603 is operated in active power control mode whereas GSVSC 601 and
GSVSC602 are in direct voltage control mode using a droop controller. Hence, the
POD is installed at the GSVSC 603. Its input signal is considered the active power
flowing in line 510-509. Finally, the slack bus of Area 1 is generator 506 while for
Area2 generator 105.
It is important for the reader to recall that the ac transmission system network (lines
and transformers) is modeled by algebraic equations using phasors, as it is common
practice in stability type simulations. Only, the synchronous generators and their
controls are represented by dynamic models represented by differential equations.
15 Area1
SG
SG
SG
GSVSC
LOAD
LOAD
LOAD
LOAD
N/A
Area2
bus #
502
506
511
603
503
504
507
509
-
MW
300
270
300
340
200
200
300
500
-
SG
SG
SG
GSVSC
GSVSC
LOAD
LOAD
LOAD
LOAD
bus #
301
102
105
601
602
602
104
103
105
MW
300
300
300
150
200
250
300
400
300
Table 1: Generation and load for the selected snapshot of the test system
Figure. 6
Two asynchronous test Power Systems connected via a MTdc network (Note: the
HVDC cable parameters and distance can be found in Appendix B and D)
16 2.1 Model of VSC-Based MTdc transmission network
The VSC station terminal is connected to the ac power system via a phase reactor and
a transformer. Normally, for bulk power system studies related to control and
stability, the VSC module is represented as a controlled voltage source from the ac
side while on the dc side as a current injection. The ac and dc sides are coupled by the
active power balance and, for the sake of simplicity, converter losses are not
considered in this study.
In PSS®E software package used in this work, all ac system dynamic models of
generation units are represented by default as controlled Norton-equivalent positive
sequence rms value current sources. For that reason the equivalent model of the VSC
on the ac side (voltage source) has been transformed to a controlled current source
equivalent. The phase reactor is modeled by linear algebraic equations and the
modulator is neglected because its dynamic response involves time constants which
are much smaller than the ac network time constants. In addition, the model of the
PLL is neglected for this case study.
On the dc side, the HVDC cables are represented by a π-equivalent model
implemented by a state space representation which can be extended to any
conceivable dc network configuration.
I source
I pr
ܷ‫ݏ‬ Cdc
jX pr
I dc =
Isource = I pr +
Pac
U dc
Us
jX pr
I pr
θs
iq
Us
U dc
iq ,ref
id
id ,ref
U sref
U dc ,ref
U dc
Q
P
Pref
Qref
Figure. 7 Model of the VSC module
17 2.2 Case study
Three case studies are considered in this report to introduce the effect of the POD
controller on the small signal stability of the onshore power system. Namely the three
case studies considered are:
1. A situation where there is no POD installed. In this case study the GSVSC and the
MTdc are not contributing to damping of power system oscillations in Area 1.
2. The POD is in operation at GSVSC3. The GSVSC3 is contributing a damping
effect to Area 1. However as it will be shown in the simulation results the operation of
the POD at the specific VSC creates direct voltage variations in the MTdc grid, as the
energy is extracted from Area 2.
3. In order to improve the dc voltage variations, the POD signal is also sent to the
active power controller of the Offshore Wind Power Plant 2 (OWPP2), in addition to
the power controller of GSVSC3.
(a) (b) Figure. 8
(a) Coordinated operation of the offshore wind power plant with the GSVSC
POD (b) Active power controller of Type 4 Wind Power Plant [15]
18 2.3 Simulation Results
A 150ms three phase fault is applied at G2 in Area 1 in order to validate the POD
controller. After the fault is cleared the generator G3 is undergoing poorly damped
power oscillations. With purpose to improve the oscillations of G3 the converter
station GSVSC3 which is located close to G3 is equipped with a POD controller. The
input of the POD is the active power of G3.
A 20s time constant is selected for the washout block. The Kdmp gain is selected to be
20 for these simulations. The active power profile of the G3 is given in Figure 9.
From the simulations response it can be seen that the operation of the POD at the
GSVSC3 can impose a damping effect at G3.
G3 active power
1
NO POD at GSVSC3
POD at GSVSC3
0.95
0.9
P (pu)
0.85
0.8
0.75
0.7
0.65
0.6
0
2
4
6
8
time(s)
Figure. 9
Active power of generator 3
10
As it can be seen the GSVSC3 station with POD introduces damping and the small
signal stability is improved significantly as a result of the modulated active power by
the GSVSC3. Figure 10 illustrates the modulated by POD active power of the
GSVSC3. It can be seen that the active power of the GSVSC3 is modulated according
to the power variations of the G3. As a result when the G3 is accelerated the GSVSC
will reduce the power injection. This change in the power flow will cause the G3 to
decelerate.
However, the modulated active power would trigger direct voltage variations in the
MTdc grid. In order to understand the above argument, the reader should recall that
the value of the direct voltage at the dc capacitor of the converter station is related to
the power balance at the dc capacitor. As a result, for the time period we are studying
where the active power injection of the wind power plants is constant, the modulation
of active power at the GSVSC produce these direct voltage variations.
19 GSVSC3 active power
1.5
NO POD
POD
P (p u )
1
0.5
0
0
Figure. 10
2
4
6
8
10
time(s)
Modulated active power of the GSVSC3 (Sb = 400MVA)
In order to minimize the direct voltage variations, a simple proposal is to add a
communication link between the GSVSC and the wind power plant (see Figure 8) in
order to coordinate the wind power plant’s and GSVSC3’s contributions to damping.
The output of the POD controller is sent also to the wind power plants which will
modulate its active power output accordingly. In this way it is possible to derive the
necessary power from the wind power plants keeping the power balance in the MTdc
network constant. In other words, the necessary power variation to damp power
oscillations is not coming in this case only from the second power system, as a result
of direct voltage control (transferring thus the problem to Area 2), but to some extent
from the wind power plants. In this way the kinetic energy stored in the wind power
plants shafts can be utilized.
Figure 11 illustrates the variations of the direct voltage at the dc capacitor of the
GSVSC3. It can be seen from the response that the operation of the POD at GSVSC
will trigger direct voltage variations.
However, when the same power variation is taking place at the wind power plant, the
power balance in the dc capacitors and thus the direct voltage variation caused by the
POD is not significant. Figure 12 shows the output power of the wind power plant.
20 Direct Voltage at DC grid node of GSVSC3
1.15
NO POD
POD at GSVSC3
POD both OWP & GSVSC
Udc (pu)
1.1
1.05
1
0.95
0.9
0
2
4
6
8
10
time(s)
direct voltage at the dc terminal of GSVSC3
Figure. 11
P offshore wind farm vs GSVSC active power
1.4
OWP2
GSVSC3
1.2
P (pu)
1
0.8
0.6
0.4
0.2
0
0
2
4
6
8
10
time(s)
Figure. 12
Active power of the Offshore wind power plant and GSVSC (Sb =
400MVA)
From the simulation results it can be stated that the dc voltages at the MTdc network
nodes are coupled and vary in the same direction. Thus, without loss of generality, it
can be argued that the dc voltages in a MTdc network is the equivalent of the
frequency in the ac power system.
The reader should recall that the frequency in the AC power system is dependent on
the power balance between generation and demand. Similarly, the dc voltage (at the
dc nodes of the MTdc network) depends on the power balance between the injected
power from the WPVSC and the GSVSC stations. It is this power balance that the
21 converters which perform dc voltage control (mainly GSVSCs) are trying to maintain
in order to keep the dc voltage at normal operation levels (adjusting their active power
injection).
Direct Voltage at DC grid nodes - NO POD
1.14
Udc1
Udc2
Udc3
Udc4
Udc4
1.12
1.1
Udc (pu)
1.08
1.06
1.04
1.02
1
0.98
0.96
0.94
0
2
4
6
8
10
time(s)
Figure. 13
Direct voltages of the MTdc network when there is NO POD
Direct Voltage at DC grid nodes - When POD on
Udc1
Udc2
Udc3
Udc4
Udc5
Udc (pu)
1.1
1.05
1
0.95
0
2
4
6
8
10
time(s)
Figure. 14
Direct voltages of the MTdc network with the POD
22 Direct Voltage at DC grid node of GSVSC
1.14
Udc1
1.12
Udc2
Udc3
1.1
Udc4
Udc5
1.08
Udc (pu)
1.06
1.04
1.02
1
0.98
0.96
0.94
0
Figure. 15
1
2
3
4
5
time(s)
6
7
8
9
10
Direct voltages of the MTdc network with POD on both OWP2 and GSVSC3
As we mentioned direct voltage variations are mirrored to the active power of the
GSVSCs, especially when they are in direct voltage control mode. Thus, the
oscillations of the direct voltage as a result of the POD would transfer the mode of
particular electromechanical oscillation we are trying to damp from system 1 via the
MTdc grid to system 2. In order to support that argument we illustrate in Figure 16
the way that GSVSC2 (system 2 which is in direct voltage control mode) active power
is influenced by the POD operating on the GSVSC3 (system 1). We can observe that
in the situation with POD there are oscillations transferred to Area2 as a result of the
POD. When the OWPP is operating in coordination with the GSVSC POD these
oscillations are minimized. The same applies for GSVSC1 in Figure 17.
23 GSVSC2 active power
0.6
NO POD
POD at GSVSC3
POD at OWP & GSVSC
0.55
P (pu)
0.5
0.45
0.4
0.35
0.3
0.25
0
2
4
6
8
10
time(s)
Figure. 16
Variation of active power at GSVSC2 as a result of pod at GSVSC3 (Sb =
400MVA)
GSVSC1 active power
NO POD
POD at GSVSC
POD at OWP and GSVSC
0.65
P (pu)
0.6
0.55
0.5
0.45
0.4
0
2
4
6
8
10
time(s)
Figure. 17
Variations of active power at GSVSC1 as a result of pod at GSVSC3
(Sb=400MVA)
Finally, it is worth discussing how the small signal stability in system 2 is influenced
by the mode which is transferred from system 1 via the MTdc grid if no action is
taken. Figure 18 introduces the response of the generator Ga in power system are2 in
the three selected cases. It can be seen from the response that the large variations of
direct voltage in the MTdc grid, if not tackled by the OWP, could trigger power
24 oscillations in both the GSVSC1 and the synchronous generators of Area2 (Figures
18, 19, 20).
GEN Ga at BUS#301 active power
0.8
0.78
0.76
P (pu)
0.74
0.72
0.7
NO POD
POD at GSVSC3
POD at GSVSC3 & OWP
0.68
0.66
0.64
0
2
4
6
8
10
time(s)
Variations of active power of Ga at system area 2
Figure. 18
GEN Gb at BUS#102 active power
0.85
0.8
P (pu)
0.75
0.7
NO POD
POD at GSVSC3
POD at both GSVSC3 and OWP
0.65
0
2
4
6
8
time(s)
Figure. 19
10
Variations of active power of Gb at system area 2
25 GEN Gc at BUS#105 active power
0.85
NO POD
POD at GSVSC3
POD both GSVSC3 & OWP
0.8
P (pu)
0.75
0.7
0.65
0
2
4
6
8
10
time(s)
Figure. 20
Variations of active power of Gc at system area 2
3. Examination of wind turbine limitations imposed on POD
contribution of OWP
A waveform of damping output power such as that shown in Figure 11 has been
assumed to be achievable by a wind farm, once dictated by the chosen POD structure.
The damping waveform should not overload power electronic converter equipment
within the wind farm. It may also be necessary to limit the frequency and amplitude
of the response commanded from the farm in order to avoid exciting mechanical and
structural resonances.
While active controls are usually in place to add damping to such resonances, any
extra energy present in such modes translates into fatigue, and can ultimately cause
higher operation costs due to early replacement of components. In this section, the
example of the torsional resonance will be explained. It can also happen that the
provision of POD functionality will require the redesign of existing damping controls.
The need to avoid resonant frequencies has been acknowledged in a recent Danish
thesis, though it did not examine such issues [25]. The same thesis demonstrated
using measurements at a real wind farm that POD commands for active power would
not necessarily be achieved. Figure 21 shows POD commands for frequencies of 0.5
Hz and slower are well transmitted to the output of a farm. For frequencies between
0.5 and 1 Hz, shifts in phase occur that would likely aggravate rather than damp
oscillations. The reason for this discrepancy was not explored. The many control
26 loops active within a wind farm have the potential to interfere with the desired power
commands, and some coupling of active power commands with reactive power
response was observed.
Excerpt from Danish thesis [25] showing failure to achieve POD commands
above 0.5 Hz. Reference (blue) compared against actual power output at PCC (red)
Figure. 21
While an actual implementation of a wind farm POD would have to account for these
issues, possibly leading to a re-design of controls, the results of Figure 21 demonstrate
that it is indeed fair to assume that a POD reference signal can be achieved by a farm
for frequencies for less than 0.5 Hz. The particular limitations or obstacles will stem
from the interaction of the wind turbine characteristics and its controls with the farm
level controls. The measurements shown in Fig. 21 are from a farm of 13, 2.3 MW
Siemens wind turbines, which have an induction generator, gearbox and full
converter. In the next section, a more realistic example is pursued with encountered
modal frequencies that are indeed no higher than 0.5 Hz for the UK system.
Even in the case that POD signals can be tracked by a farm in order to induce the
desired damping, it can still be important to consider the effect of adding extra energy
to damped mechanical resonances. It is argued here that the torsional resonance of a
wind turbine provides another reason to limit the operation of wind farm PODs to
frequencies less than 0.5 Hz or less.
27 The mechanical mode of primary relevance in a wind turbine to grid imposed
disturbances is known as the drive-train mode, and consists of the generator mass and
an outer fraction of the rotor blades swinging against each other [17]. While other
modes of the turbine occur in the range 0.1-1 Hz, they are either relatively highly
damped (the blade flap modes) or coupled mostly to pitch, rather than generator
torque (tower modes) [18].
The frequency of this mode is determined by rotor and generator inertias, and the
effective compliance of the turbine shaft and blades. The relatively large compliance
is attributed to the collective torsional flex of blades, and the speed ratio from the
rotor to the generator, which is large regardless [26] of whether there is a gearbox, or
a large number of pole pairs as in the case of a direct drive turbine. The actual
observed frequency may differ significantly from what might be inferred from the
rotor’s total inertia, because blade flexibility makes it difficult to determine what
fraction of inertia to assign to which equivalent rotational inertia in a two mass model,
and what compliance to use [17].
The computed and reported value for the parameter can range from 0.6-4.0 Hz,
depending on the size of the machine. ECN system identification tests based on
actual measurements of a 3 MW wind turbine anticipated a frequency in the range of
0.7 to 1.0 Hz, and identified a mode with frequency 0.87 [19]. A frequency of 0.6 Hz
is evident from high-resolution gearbox test measurements of a 2MW wind turbine
(private communication) and a similar frequency has been computed through detailed
structural analysis of the 5MW NREL offshore reference turbine [20]. The destabilization of this mode when a wind turbine is equipped with a POD has been
demonstrated [6]. The same work compared PODs based on active and reactive
power. It has also been demonstrated how to design controls to achieve damping of
both the turbine shaft and power system modes [21]. The threshold for when extra
stresses on the mechanical system necessitate limiting of a POD or alterations to the
controls is likely to be an issue of manufacturer discussion. A baseline of stresses
based on wind variation drivers could be taken for comparison.
The example of the previous section demonstrated the concept of how a POD at a
GSVSC may help one ac-system, but potentially transfer oscillations to another acsystem, and how coordinated injection of active power by an offshore wind farm can
prevent this by cancelling direct voltage variations in the MTDC network. The
practicality of such a contribution should be considered more carefully through an
analysis of wind turbine small-signal dynamics. This falls outside the scope of this
report.
28 4 A case study of UK equivalent model coupled with the Nordic
power system via a multi-terminal VSC-HVDC offshore network
As a second experiment in this report we will introduce the coupling of the UK
equivalent benchmark power system model as given in [16] with the Nordic power
equivalent system model given in [22]. The same MTdc grid layout is used as in
Section 2 with the same rated values and snapshot, for the sake of simplicity, and the
configuration is shown in Figure 22.
The generated power from the two offshore wind power plants is transported onshore
via the MTdc network to both asynchronous power systems. So the power flow
direction in this case study is from wind power plants to the two asynchronous
onshore power systems. The control of the direct voltage in the MTdc offshore
network is performed by the two GSVSCs of the Nordic system which both
implement active power-direct-voltage droop characteristic.
6100
400MW Offshore Wind Power Plant
North UK
6001
6000
PCC
NORDIC
Power system ac
ac
1001
3
dc WPVSC
1002
dc
GSVSC
1008
5600
6
0.5Hz
20km
dc
ac
GSVSC
1003
5601
1
5
WPVSC
ac
2
4
PCC
dc
1004
GSVSC
400MW Offshore Wind Power Plant
South UK
ac
dc
HVDC cable
L36, L46, L56=100km
L16, L26=20km
1005
1007
1006
Figure. 22
UK power system connected to the Nordic system by a MTdc grid
4.1 Nordic power system model
The detailed Nordic system consists mainly of 3000 buses, 4000 branches and 1100
generators. However, it has been reduced as proposed in [22] to an equivalent
benchmark model of 36 buses which is composed of 20 large generators which
represent each area in the Nordic system. Standard IEEE 6th order model of
synchronous generators have been used, with IEEET2 excitation system and IEEEG0
29 governor model. Power system stabilizers STAB2A are in operation at certain
generators in the Nordic system.
Two critical inter-area modes are present in the Nordic system, which can be
reproduced as well in the equivalent model [23]. Namely, there is the 0.29 Hz mode,
which is the inter-area oscillation of the Finish generators against the rest of Nordic
system. The second mode includes the 0.55Hz oscillations between Finland against
Sweden, North Finland and Norway. Figure 23 gives a graphical representation of the
equivalent model.
The landing point of the MTdc network for this report is considered the Norwegian
south-west coast line, as illustrated in Figure 22. More specifically, two landing points
are considered, at buses 5600 and 6000 respectively. Both the converter stations are in
direct voltage control mode operating as slack bus for the MTdc network.
Figure. 23
Equivalent model of the Nordic power system used in this report [22]
4.2 UK power system model
This study is based on an 8-node, 6-load and 7-generator power system which
represents a benchmark model of the UK 380kV transmission system as given in [16].
The model represents a large network which has been reduced to a small number of
nodes. Appendix A gives a picture of the aggregation adapted in the UK system.
According to [16] this model has been developed and evaluated in collaboration with
National Grid and is reproduced in the present project. Furthermore, this model is an
30 extension of the three generator system model presented in [24]. The network model
is tuned for the present report for a light load situation. The main reason is basically
that the system for heavy load situation is exhibiting unstable modes of
electromechanical oscillations which are normally stabilized by use of power system
stabilizers (PSS) at the synchronous generators excitation system. However, such
parameters of PSS are not available for this study. For that reason only a low-load
profile situation which exhibits the necessary for this report inter-area 0.5Hz mode of
oscillations is considered. No power system stabilizers are in use in the UK system,
for the case study of this project.
All generators (mainly equivalent generators that represent areas) in the UK system
are modeled by the 6th order standard IEEE dynamic models and with dedicated
parameters [16]. The same applies for line impedances. With regards to the excitation
system and governor, standard IEEE models (TGOV1 & SEXS) and standard
parameters are used.
It is important for the reader to keep in mind that in this report we are interested to
illustrate the interaction among two asynchronous systems coupled with a MTdc
network from small signal stability point of view and how the last can be improved.
As soon as the modes of electromechanical oscillations are close to the modes
observed from National Grid, the simplifications taken (mainly excitation system and
governor control parameters) are considered adequate.
The proposed UK model illustrates various local modes and an inter-area mode of
electromechanical oscillations. The inter-area mode is 0.5Hz for the particular unitcommitment scheme and is between the North part of the system (G1 and G2) which
represents north and south Scotland and the South part (G1 until G7) which represents
the main and South England.
4.3 Simulation results
By observation of the time domain simulations for a 140ms three phase symmetrical
fault at bus 1007 (140ms is the fault duration that National Grid requires for
generators to stay connected), the voltage profiles of the UK model is given in Figure
24. The presence of the inter-area mode of 0.5Hz is visible in all voltage profiles.
31 Uac at UK system
1.4
1.2
U (pu)
1
0.8
1.5
0.6
1
0.4
0.5
0.2
0
#1001
#1002
#1003
#1004
#1005
#1006
#1007
#1008
0
0
Figure. 24
2
4
1
6
1.5
8
2
10
time(s)
2.5
12
3
14
16
18
20
Voltage profile at the busses of the UK power system model for 140ms three
phase symmetrical fault at bus 1007
Figure 25 introduces the response of the UK power system synchronous generators. It
can be seen that apart from the local modes (which are relevantly fast damped) there
is also an inter-area mode of ~0.5Hz frequency with very poor damping, exactly as
expected. Furthermore, in this mode are participating mainly two groups of
generators, namely G1, G2 (North and South Scotland) against G3,4,5,6,7 which are
the rest system generators (main and south England). From these time domain plot it
is obvious that the model is reproducing the inter-area mode present in the UK system
as shown in [16].
32 10
x 10
-3
SPD UK GENS NO POD
G1
G2
G3
G4
G5
G6
G7
-4
5
8
x 10
3
1
SPD deviation (pu)
6
-1
-3
4
-5
10
12
14
16
time(s)
18
20
2
0
-2
-4
0
2
4
6
8
10
time(s)
12
14
16
18
20
Figure. 25 Speed deviations (Δω) of the UK power system generators for 140ms
symmetrical fault at bus 1007
The hypothesis we are going to prove is that the GSVSC that has been located at bus
1002 of the UK power system is capable of damping this inter-area mode of
electromechanical oscillation by utilization of the proposed simple type POD at the
GSVSC which is connected next to North Scotland generator. The same concept as in
the previous simple test system is applied. The input of the POD at GSVSC is the
power oscillations of the generator G2. The idea is that damping out the oscillations
of the G2 will have a positive effect at the inter-area mode.
Before discussing the time domain simulations with the proposed POD in operation,
we are going first to illustrate the response of direct voltages in all five dc nodes of
the MTdc network, as shown in Figure 26. In addition, Figure 27 gives the active
power response of the three GSVSCs.
33 Udc at MTdc grid Nodes
1.15
1.05
1
1.1
Udc (pu)
Udc1
Udc2
Udc3
Udc4
Udc5
0.95
1.05
1
1.05
1.1
1.15
1.2
8
10
time(s)
1
0.95
0
2
4
6
12
14
16
18
20
Figure. 26
Direct voltage variation at the dc nodes of the MTdc offshore network
GSVSC power response NO POD
0.5
GSVSC #6000
GSVSC #5600
GSVSC # 1002
0.45
0.4
P (pu)
0.35
0.3
0.25
0.2
0.15
0.1
0
0.5
1
1.5
2
2.5
3
3.5
4
4.5
5
time(s)
Figure. 27
Active power response from the ac side of the GSVSCs connected to the
MTdc grid (Sb=1000MVA)
34 From the time domain simulations, it can be observed that the ac side voltage drop in
the ac terminal of the GSVSC 1002 creates an active power drop at the GSVSC 1002.
As a result of the fault, the power balance at the dc capacitor is lost and the direct
voltage at the dc side will rise. However, the voltage rise is below the dc chopper
threshold, and the chopper is not activated. After the fault is cleared, both direct
voltage and active power return back to their pre-fault operating point in quite short
time.
There are two things the reader should notice. The first is the active power overshoot
that appears in the Nordic system GSVSCs (at bus 5600 and 6000). This is the result
of the dc side overvoltage at the dc terminals. The droop controllers will react in this
case by increasing active power injection.
The second is that there is no significant participation of the GSVSC at the power
oscillations of the UK system. The very small variations are mainly created by the ac
side voltage variations as has been shown in Figure 24. Furthermore, there is full
decoupling of the offshore wind power plant’s inertia from the ac system. The last
argument will be discussed later and examples will be given.
4.3.1 Simulation results with POD at GSVSC of the UK system
This paragraph will introduce the time domain response of the UK power system
model with the GSVSC 1002 equipped with a POD controller. The design of the POD
controller has followed the same approach as in the previous example of Section 2.
First a washout time constant is selected adequate enough to filter low frequency
phenomena. Then a small POD gain is selected. Then it has been increased such as it
both adds damping without creating unstable modes of oscillations. Figure 28
illustrate the voltage profiles for the same fault.
Uac at UK system
1.2
1
U (pu)
0.8
1.5
#1001
#1002
#1003
#1004
#1005
#1006
#1007
#1008
0.6
1
0.4
0.5
0
0.2
0
Figure. 28
0
2
4
1
1.5
6
8
10
time(s)
2
12
14
16
18
20
Ac voltage profiles in the UK power system when the POD at GSVSC 1002
is in operation
35 Comparing the response of the synchronous generator active power it is clear that
there is positive effect of the proposed POD at the small signal stability of the UK
power system. Figure 29 introduces the time domain simulations for selected
generators with and without the POD at GSVSC 1002. In all situations the
improvement in the damping time is significant. As a consequence, the simple type
POD is not only a simple approach for damping inter-area modes of
electromechanical oscillations but also seems not to negatively influence the other
generators in the same system, at least for the case studies presented in this report.
UK G1 active power
UK G2 active power
1
1.6
1.5
0.9
1.4
0.8
~0.5Hz
0.85
1.2
1.54
1.52
1.1
0.8
1
P (pu)
P (pu)
1.3
~0.5Hz
0.9
0.75
0.95
1.05
1.15 1.2
time(s)
0.7
0
2
4
1
0.6
0.8
1.5
6
8
10
time(s)
1.46
0.6
0.5
1.48
0.8
0.7
0.4
14.5
15.5
time(s)
14
16
12
0.4
16.5
18
20
0.95 1.05 1.15 1.25 1.35 1.45
1.5
0
2
4
6
NO POD
POD
UK G3 active power
8
10
time(s)
12
14
16
18
20
14
16
18
20
UK G5 active power
0.35
1.1
0.3
1
0.25
P (pu)
P (pu)
0.9
0.2
0.15
0.8
0.7
0.1
0.6
0.05
0.5
0
0.4
0
2
4
6
8
10
time(s)
Figure. 29
12
14
16
18
20
0
2
4
6
8
10
12
time(s)
Power oscillations of selected generators in UK power system with and
without POD at GSVSC of bus 1002 (Sb =1000MVA)
In addition, for the case of the G2 generator, the speed deviation for the two above
mentioned case studies is illustrated in Figure 30. Finally, Figure 31 illustrates the
speed deviation response of the UK power system generators.
Figure 32 illustrates the active power variation of the GSVSC of bus 1002 in the UK
system, as modulated by the POD. In this graph it can be seen how the GSVSC active
power is changed accordingly in order to participate in the power oscillation and thus
reduce the oscillations of the G2. It is important at this point to refer to the limiter of
the POD (see Figure 5). As can be seem the limiter of the POD is responsible to keep
the variation of the active power within acceptable levels. The main reason for
36 restricting the GSVSC active power is the direct voltage variations created in the
MTdc network as shown in Figure 33.
x 10
4
-3
SPD UK G2 WITH/WITHOUT POD
POD
NO POD
SPD deviation (pu)
3
2
0.5Hz
1
0
-1
-2
0
2
4
6
8
10
12
14
16
18
20
time(s)
Figure. 30
G2 speed deviation with and without POD at GSVSC of bus 1002
10
x 10
SPD UK GENS WITH POD
-3
-4
SPD deviation (pu)
3
x 10
-1.5
10
5
12
14
16
time(s)
6
8
18
G1
G2
G3
G4
G5
G6
G7
20
0
-5
0
2
4
10
12
14
16
18
20
time(s)
Figure. 31
UK power system synchronous generators speed deviations Δω - With POD
at GSVSC of bus 1002 in the UK power system
37 GSVSC at bus 1002
0.6
0.4
When there is NO POD
GSVSC will quickly return to the prefault
operating point and will not participate in the
power system Oscillations
0.3
0.5
0.2
1
1.2
P (pu)
0.4
0.3
The Oscillation created by the POD
to counteract the oscillatons of G2
and thus damp the inter-area mode
0.2
0.1
0
POD
Here the Lower Limit of the POD is reached.
This can be seen also by the dc voltage variation.
0
2
4
6
8
10
12
NO POD
14
16
18
20
time(s)
UK power system GSVSC - With POD
Figure. 32
Udc at MTdc grid Nodes WITH POD
1.15
At this point, the lower limit of the POD
is reached, this point should always be below
1.1 pu to prevent dc chopper from being triggered
1.1
Udc 1
Udc2
Udc3
Udc4
Udc5
Udc (pu)
1.05
1
0.95
The same should apply for the direct voltage oscillations,
both the max and min value should be kept within
the dc voltage operational limits
0.9
0.85
0.8
0
2
4
6
8
10
time(s)
12
14
16
18
20
Figure. 33
Direct voltage variations created by the POD of GSVSC at bus 1002 of UK
power system when POD is in operation
38 In addition, as it can be observed in the time domain response of the direct voltage
profiles, the inter-area mode is mirrored in the direct voltage in dc nodes of the MTdc
network. The droop controllers of the GSVSCs in the Nordic system will try to
control and maintain the direct voltage at their dc nodes. These direct voltage
variations will create active power oscillations of the GSVSC converter operating in
the south-west coast of Norway.
As a result the direct voltage variations are reflected to the Nordic system VSCs as it
can be seen in Figure 34. Consequently, damping of power oscillations in one
asynchronous power system, such as the UK system, can be achieved but special care
need to be taken in order not to propagate these modes via the MTdc grid direct
voltage variations.
GSVSC at 6000 bus of Nordic system
0.3
POD
NO POD
P (pu)
0.25
0.2
0
2
4
6
8
10
time (s)
12
14
16
18
20
GSVSC at bus 5600 of the Nordic system
0.25
P (pu)
0.2
0.15
0.1
0
2
Figure. 34
4
6
8
10
time (s)
12
14
16
18
20
Active Power profiles of GSVSCs in the Nordic system
For the specific case study, the effect that the active power variations in the GSVSC
5600 has on the synchronous generator connected at bus 5600 is shown in Figure 35.
From the response it can be concluded that the operation of the MTdc network is
triggering a 0.5Hz mode in the Nordic system which needs to be tackled
appropriately. The main excitation source of this oscillation is the 0.5Hz mode of the
UK system, which is transferred to the Nordic system via the MTdc offshore network.
In addition, when the POD is in operation in the UK system GSVSC the amplitude of
this mode in the active power response of the generator 5600 is double.
39 Generator 5600 at Norway
2.6
NO POD
POD at GSVSC 1002
2.5
2.4
P(pu)
2.3
Zoomed
2.2
2.4
2.39
2.1
2.38
2.37
2
2.36
1.9
1.8
2.35
0
2
4
5
6
6
7
8
8
9 10 11 12 13 14 15 16 17 18 19 20
10
12
14
16
18
20
time(s)
Figure. 35
Active Power profiles of synchronous generator at bus 5600 (Norway,
Sb=1000MVA)
4.3.2 Simulation results with POD at GSVSC of the UK system and POD at OWPs
In order to limit the effect that the operation of the POD has on the direct voltage of
the MTdc network, the same approach as in the case study of Section 2 is considered.
The output of the POD is sent via a communication link to the controller of the
offshore wind power plant. As a result the active power of the wind power plant is
varied accordingly. In the first approach proposed in this report, the communication
link is not considered. Normally, there is a delay of approximately 50ms, taken into
account that the power variations are much slower (~0.5Hz or lower) the time delay
would not significantly affect the response of the system.
In the case that the active power of the wind power plant is varied according, the
direct voltage variations are kept at the same level as in the case where the POD is not
operating. Figure 37 illustrates the direct voltage profiles in the MTdc network. From
that it can be seen that the coordination of the POD with the offshore wind power
plants would limit the direct voltage oscillations.
40 VSCs active power response in the MTdc grid
0.8
GSVSC 5600 (Norway)
GSVSC 6000 (Norway)
Wind Power Plant 2
GSVSC 1002 (UK)
0.4
0.7
0.3
0.2
0.6
0.1
1
1.5
2
P (pu)
0.5
0.4
0.3
0.2
0.1
0
2
4
6
8
10
time(s)
12
14
16
18
20
Figure. 36
Active power response of the VSC of the MTdc grid when there is both POD
at GSVSC 1002 and the offshore wind power plant
Udc at MTdc grid Nodes WITH POD at OWP
1.08
Udc1
Udc2
Udc3
Udc4
Udc5
1.04
1.06
1.02
1
1.04
Udc (pu)
1
1.2
1.4
1.6
1.8
2
1.02
1
0.98
0
2
4
6
8
10
12
14
16
18
20
time(s)
Figure. 37
Direct voltage variations with both POD at GSVSC 1002 and offshore wind
power plants 2
41 Generator 5600 at Norway
2.6
NO POD
POD
POD & OWPP POD
2.5
2.4
P(pu)
2.3
2.4
2.2
2.39
2.1
2.38
2
2.37
2.36
1.9
2.35
1.8
0
2
5
6
4
7
8
6
9
10
8
11
12
10
time(s)
13
12
14
15
14
16
17
16
18
19
18
20
20
Figure. 38
Active Power profiles of synchronous generator at bus 5600 (Norway,
Sb=1000MVA)
Finally, Figure 38 illustrates the time domain response of the generator 5600 at the
Nordic system in the three investigated cases. From the response it can be seen that
the coordination between the OWPP and the GSVSC will reduce the power
oscillations to the level they were when the POD was not in operation.
42 5 Conclusions and discussion
This report discussed the small-signal damping capabilities of VSC-HVDC offshore
MTdc networks. A simple proportional POD controller type with a gain and washout
block was proposed. This acts as a supplementary control signal to the active power
reference set-point of VSCs in active power control mode.
A small test system has been used in order to investigate the performance of the POD
controller in damping power system oscillations. The POD acts at the active power
controller of the GSVSC changing the active power reference accordingly. As a
second and more realistic case study, the UK equivalent model is used, which has
been coupled via a VSC-HVDC multi-terminal grid to a Nordic power system
equivalent model. The UK power system illustrates a critical power oscillation mode
of 0.5Hz. The hypothesis proved in this report is that this lightly damped oscillation
can be damped out effectively by the GSVSC station connected next the NorthScotland equivalent generator. This has been shown via time domain simulations. The
damping of the 0.5 Hz (North-South) UK system mode is achieved in short time
without jeopardizing the local modes or driving particular modes related to unstable
oscillations. The proposed control design is both easy in implementation and does not
require sophisticated methods of tuning since it consists only of a single gain. Its
damping capability is based on simple physical considerations.
However, the simulation results showed that the operation of the POD controller at
the GSVSC terminal can induce direct voltage variation in the MTdc network, with
the same frequency as the mode the POD is trying to damp out. In addition, these
variations are not related to the type of the POD used (PSS type or simple
proportional with washout block) but rather to the direct relation of the direct voltage
of the dc side of the GSVSC with the active power injection, at the ac terminal. This
interaction needs be tackled in order not to transfer the mode of oscillation from one
asynchronous system, via the MTdc network, to the second.
To solve this problem, coordination between the GSVSC and the OWPP could limit
the direct voltage variations created by the POD operating on the GSVSC. What is
more, it engages offshore wind power plants to participate in the damping of onshore
power system by use of their rotor-blades inertia, which in the case of MTdc networks
is fully de-coupled from the ac system. In addition, the proposed coordination of the
supplementary control signal sent via communication link between Offshore Wind
Power Plants and GSVSC will fix the problem of decoupling of the wind turbines
speed from the system frequency. It has been argued that both wind farm test results
and expected trends in wind turbine structure suggest that active power PODs can be
added to wind turbines without further modifications provided the frequency is lower
than the drive-train torsional mode.
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45 Appendix A
Figure illustrating the aggregation of the UK power system areas [16]. As it can be
seen each generator in the UK equivalent model is a representation of an area.
46 Appendix B
Parameters of the HVDC lines in figure 6 & 21
Rdc=0.03 Ohms/km
Ldc= 0.2 mH/km
Cdc=220nF/km
For the VSC
Cdc_VSC=50uF (this is the dc capacitor of the VSC converter station)
47 Appendix C
Representation of the Nordic power system [22] equivalent model as is used in the
PSS®E simulation tool.
48 Appendix D
Distances of the HVDC cables in figure 6
From dc bus
To dc bus
Length (km)
1
6
100
2
6
100
3
6
100
4
6
20
5
6
20
Appendix E
Equation of the active power of a transmission line
U2 δ2
U 1 δ1
݆ܺ Pline =
U1U 2
sin(δ1 − δ 2 )
X
49