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1 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
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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
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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.
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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.
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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 multi-terminal 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
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List of Symbols
prI Phasor of the phase reactor current sourceI Phasor of the current source of the Norton VSC equivalent model
prX Phase reactor reactance installed at the converter station
prR Resistance of the equivalent model of the phase reactor
dcR Resistance of the π-equivalent model of HVDC cable
dcL Inductance of the π-equivalent model of HVDC cable
dcC Capacitor of the π-equivalent model of HVDC cable
dcI Dc current injection at terminal of the HVDC cable
dcU Direct voltage at the multi-terminal DC network
sU Phasor of the AC voltage at the AC grid connection point of the converter station
qi q-axis component of the phase reactor current di d-axis component of the phase reactor current
pccU Phasor of the converter voltage at point of common coupling
refP Active power reference of the converter station
refQ Reactive power reference of the converter station
P Active power of the converter station Q Reactive power of the converter station
pk Proportional gain of the PI controller
ik Integral gain of the PI controller refPΔ Output signal of the Power oscillation damper controller
maxPΔ Upper limiter of the Power Oscillation Damper (POD) controller
minPΔ Lower limiter of the Power Oscillation Damper (POD) controller
wT Power Oscillation Damper controller washout block time constant
dmpK Proportional gain of the Power Oscillation Damper Controller
pssK Proportional gain of the classic Power System Stabilizer
owpPΔ Modulated offshore wind park active power
GSVSCPΔ Modulated grid side VSC active power sθ Voltage angle at the AC side connection point of the VSC
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List of Acronyms ac Alternative current AVR Automatic Voltage Regulator dc Direct current FRT Fault Ride Through GSVSC Grid side voltage source converter HVDC High Voltage Direct Current IGBT Insulated Gate Bipolar Transistor MTdc Multi-terminal Direct Current NSTG North Sea Transnational Grid PCC Point of Common Coupling PI Proportional Integral controller PLL Phase Lock Loop POD Power Oscillation damper PSS Power System Stabilizer PWM Pulse Width Modulation VSC Voltage Source Converter OWPP Offshore Wind Power Park WPVSC Wind Park voltage source converter
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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 Variation of active power at GSVSC2 as a result of pod at GSVSC3 (Sb = 400MVA) 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
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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 Ac voltage profiles in the UK power system when the POD at GSVSC 1002 is in operation 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
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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
Modulation of Series
Impedance
POD in the AC system
POD using the turbine-generator
unit
Modulation of Active Power
Modulation of Reactive Power
Application of a Power System
StabilizerPSS
Figure. 1 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].
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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
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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 multi-terminal 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.
ip
kks
+refdcU
dcU
di
ip
kks
+refPdi
ip
kks
+ qi
ip
kks
+refsU
sU
qi
P
refQ
Q
+
−
+
−
+
−
+
−
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
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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.
dcdc
VV ip
KKs
+
pssK
maxPΔ
minPΔ
1
2
11
nsTsT
⎛ ⎞+⎜ ⎟+⎝ ⎠ 1
w
w
sTsT+
refPΔ
refP
P
di
lineP
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
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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.
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dcdc
VV ip
KKs
+
dmpK
maxPΔ
minPΔ1
w
w
sTsT+
refPΔ
refP
P
di
lineP
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.
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Area1 Area2 bus # MW bus # MW SG 502 300 SG 301 300 SG 506 270 SG 102 300 SG 511 300 SG 105 300 GSVSC 603 340 GSVSC 601 150 LOAD 503 200 GSVSC 602 200 LOAD 504 200 LOAD 602 250 LOAD 507 300 LOAD 104 300 LOAD 509 500 LOAD 103 400 N/A - - LOAD 105 300
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)
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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.
acdc
dc
PIU
=
dcC dcUprjX
ssource pr
pr
UI IjX
= +
sU
PQ
refsU
refQrefP
,dc refU
dcU
,d refi,q refi
diqi
sθprI
prI sourceI
Figure. 7 Model of the VSC module
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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]
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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.
0 2 4 6 8 100.6
0.65
0.7
0.75
0.8
0.85
0.9
0.95
1 G3 active power
P (p
u)
time(s)
NO POD at GSVSC3 POD at GSVSC3
Figure. 9 Active power of generator 3
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.
20
0 2 4 6 8 100
0.5
1
1.5 GSVSC3 active power
P (p
u)
time(s)
NO PODPOD
Figure. 10 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.
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0 2 4 6 8 100.9
0.95
1
1.05
1.1
1.15 Direct Voltage at DC grid node of GSVSC3
Udc
(pu)
time(s)
NO PODPOD at GSVSC3POD both OWP & GSVSC
Figure. 11 direct voltage at the dc terminal of GSVSC3
0 2 4 6 8 100
0.2
0.4
0.6
0.8
1
1.2
1.4 P offshore wind farm vs GSVSC active power
P (p
u)
time(s)
OWP2GSVSC3
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
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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).
0 2 4 6 8 10
0.94
0.96
0.98
1
1.02
1.04
1.06
1.08
1.1
1.12
1.14
Direct Voltage at DC grid nodes - NO POD
Udc
(pu)
time(s)
Udc1Udc2Udc3Udc4Udc4
Figure. 13 Direct voltages of the MTdc network when there is NO POD
0 2 4 6 8 10
0.95
1
1.05
1.1
Direct Voltage at DC grid nodes - When POD on
Udc
(pu)
time(s)
Udc1Udc2Udc3Udc4Udc5
Figure. 14 Direct voltages of the MTdc network with the POD
23
0 1 2 3 4 5 6 7 8 9 10
0.94
0.96
0.98
1
1.02
1.04
1.06
1.08
1.1
1.12
1.14
Direct Voltage at DC grid node of GSVSC
Udc
(pu)
time(s)
Udc1
Udc2
Udc3
Udc4
Udc5
Figure. 15 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.
24
0 2 4 6 8 100.25
0.3
0.35
0.4
0.45
0.5
0.55
0.6 GSVSC2 active power
P (p
u)
time(s)
NO PODPOD at GSVSC3POD at OWP & GSVSC
Figure. 16 Variation of active power at GSVSC2 as a result of pod at GSVSC3 (Sb =
400MVA)
0 2 4 6 8 100.4
0.45
0.5
0.55
0.6
0.65
GSVSC1 active power
P (p
u)
time(s)
NO PODPOD at GSVSCPOD at OWP and GSVSC
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
25
oscillations in both the GSVSC1 and the synchronous generators of Area2 (Figures 18, 19, 20).
0 2 4 6 8 100.64
0.66
0.68
0.7
0.72
0.74
0.76
0.78
0.8 GEN Ga at BUS#301 active power
P (p
u)
time(s)
NO PODPOD at GSVSC3POD at GSVSC3 & OWP
Figure. 18 Variations of active power of Ga at system area 2
0 2 4 6 8 10
0.65
0.7
0.75
0.8
0.85 GEN Gb at BUS#102 active power
P (p
u)
time(s)
NO PODPOD at GSVSC3POD at both GSVSC3 and OWP
Figure. 19 Variations of active power of Gb at system area 2
26
0 2 4 6 8 10
0.65
0.7
0.75
0.8
0.85 GEN Gc at BUS#105 active power
P (p
u)
time(s)
NO PODPOD at GSVSC3POD both GSVSC3 & OWP
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
27
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.
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)
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.
28
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 de-stabilization 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 ac-system, 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.
29
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.
5600
6000
6100
6001
5601
ac
dc
ac
dc
NORDICPower system ac
dc
dc
ac
North UK
1
2
3
45
PCC
PCC
GSVSC
GSVSC
WPVSC
WPVSC
400MW Offshore Wind Power Plant
400MW Offshore Wind Power Plant
1001 1008
1002
1003 1004
1007
1005
1006
ac
dc
GSVSC
South UK
0.5Hz 20km
6
L36, L46, L56=100kmL16, L26=20km
HVDC cable
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
30
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
31
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 unit-commitment 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.
32
0 2 4 6 8 10 12 14 16 18 200
0.2
0.4
0.6
0.8
1
1.2
1.4 Uac at UK system
U (p
u)
time(s)
1 1.5 2 2.5 30
0.5
1
1.5 #1001#1002#1003#1004#1005#1006#1007#1008
Figure. 24 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].
33
0 2 4 6 8 10 12 14 16 18 20-4
-2
0
2
4
6
8
10x 10
-3 SPD UK GENS NO POD
SP
D d
evia
tion
(pu)
time(s)
10 12 14 16 18 20-5
-3
-1
1
3
5x 10-4
time(s)
G1G2G3G4G5G6G7
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.
34
0 2 4 6 8 10 12 14 16 18 200.95
1
1.05
1.1
1.15 Udc at MTdc grid Nodes
Udc
(pu)
time(s)
1 1.05 1.1 1.15 1.20.95
1
1.05 Udc1Udc2Udc3Udc4Udc5
Figure. 26 Direct voltage variation at the dc nodes of the MTdc offshore network
0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 50.1
0.15
0.2
0.25
0.3
0.35
0.4
0.45
0.5GSVSC power response NO POD
P (p
u)
time(s)
GSVSC #6000GSVSC #5600GSVSC # 1002
Figure. 27 Active power response from the ac side of the GSVSCs connected to the MTdc grid (Sb=1000MVA)
35
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.
0 2 4 6 8 10 12 14 16 18 200
0.2
0.4
0.6
0.8
1
1.2
Uac at UK system
U (p
u)
time(s)
#1001#1002#1003#1004#1005#1006#1007#10081 1.5 2
0
0.5
1
1.5
Figure. 28 Ac voltage profiles in the UK power system when the POD at GSVSC 1002
is in operation
36
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.
0 2 4 6 8 10 12 14 16 18 200.4
0.5
0.6
0.7
0.8
0.9
1
1.1
UK G5 active power
P (p
u)
time(s)
0 2 4 6 8 10 12 14 16 18 200.7
0.8
0.9
1
1.1
1.2
1.3
1.4
1.5
1.6
UK G1 active power
P (p
u)
time(s)
0 2 4 6 8 10 12 14 16 18 20
0.4
0.5
0.6
0.7
0.8
0.9
1 UK G2 active power
P (p
u)
time(s)
0 2 4 6 8 10 12 14 16 18 200
0.05
0.1
0.15
0.2
0.25
0.3
0.35 UK G3 active power
P (p
u)
time(s)
0.95 1.05 1.15 1.25 1.35 1.451.5
0.4
0.6
0.8
1
0.95 1.05 1.15 1.20.75
0.8
0.85
time(s)
NO PODPOD
14.5 15.5 16.51.46
1.48
1.5
1.52
1.54
time(s)
~0.5Hz
~0.5Hz
Figure. 29 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
37
restricting the GSVSC active power is the direct voltage variations created in the MTdc network as shown in Figure 33.
0 2 4 6 8 10 12 14 16 18 20-2
-1
0
1
2
3
4x 10
-3 SPD UK G2 WITH/WITHOUT POD
SP
D d
evia
tion
(pu)
time(s)
PODNO POD
0.5Hz
Figure. 30 G2 speed deviation with and without POD at GSVSC of bus 1002
0 2 4 6 8 10 12 14 16 18 20-5
0
5
10x 10
-3 SPD UK GENS WITH POD
SP
D d
evia
tion
(pu)
time(s)
G1G2G3G4G5G6G7
10 12 14 16 18 20-1.5
3x 10-4
time(s)
Figure. 31 UK power system synchronous generators speed deviations Δω - With POD
at GSVSC of bus 1002 in the UK power system
38
0 2 4 6 8 10 12 14 16 18 200
0.1
0.2
0.3
0.4
0.5
0.6 GSVSC at bus 1002
P (p
u)
time(s)
PODNO POD
1 1.20.20.30.4
The Oscillation created by the PODto counteract the oscillatons of G2and thus damp the inter-area mode
When there is NO PODGSVSC will quickly return to the prefault
operating point and will not participate in the power system Oscillations
Here the Lower Limit of the POD is reached.This can be seen also by the dc voltage variation.
Figure. 32 UK power system GSVSC - With POD
0 2 4 6 8 10 12 14 16 18 200.8
0.85
0.9
0.95
1
1.05
1.1
1.15
Udc at MTdc grid Nodes WITH POD
Udc
(pu)
time(s)
Udc 1Udc2Udc3Udc4Udc5
The same should apply for the direct voltage oscillations,both the max and min value should be kept within
the dc voltage operational limits
At this point, the lower limit of the PODis reached, this point should always be below
1.1 pu to prevent dc chopper from being triggered
Figure. 33 Direct voltage variations created by the POD of GSVSC at bus 1002 of UK power system when POD is in operation
39
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.
0 2 4 6 8 10 12 14 16 18 20
0.2
0.25
0.3
time (s)
P (p
u)
GSVSC at 6000 bus of Nordic system
0 2 4 6 8 10 12 14 16 18 200.1
0.15
0.2
0.25
time (s)
P (p
u)
GSVSC at bus 5600 of the Nordic system
PODNO POD
Figure. 34 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.
40
0 2 4 6 8 10 12 14 16 18 201.8
1.9
2
2.1
2.2
2.3
2.4
2.5
2.6 Generator 5600 at Norway
P(p
u)
time(s)
5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 202.35
2.36
2.37
2.38
2.39
2.4Zoomed
NO PODPOD at GSVSC 1002
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.
41
0 2 4 6 8 10 12 14 16 18 200.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8VSCs active power response in the MTdc grid
P (p
u)
time(s)
GSVSC 5600 (Norway)GSVSC 6000 (Norway)Wind Power Plant 2GSVSC 1002 (UK)
1 1.5 20.1
0.2
0.3
0.4
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
0 2 4 6 8 10 12 14 16 18 20
0.98
1
1.02
1.04
1.06
1.08 Udc at MTdc grid Nodes WITH POD at OWP
Udc
(pu)
time(s)
1 1.2 1.4 1.6 1.8 2
1
1.02
1.04
Udc1Udc2Udc3Udc4Udc5
Figure. 37 Direct voltage variations with both POD at GSVSC 1002 and offshore wind power plants 2
42
0 2 4 6 8 10 12 14 16 18 201.8
1.9
2
2.1
2.2
2.3
2.4
2.5
2.6 Generator 5600 at Norway
P(p
u)
time(s)
NO PODPODPOD & OWPP POD
5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 202.35
2.36
2.37
2.38
2.39
2.4
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.
43
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 North-Scotland 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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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.
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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)
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Appendix C Representation of the Nordic power system [22] equivalent model as is used in the PSS®E simulation tool.
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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
1 1U δ 2 2U δ
1 2
1 2sin( )lineU UP
Xδ δ= −
