The Royal Institute of Technology Department of Electrical Engineering Electric Power Engineering
VALIDATION OF THE PSS/E MODEL FOR THE GOTLAND NETWORK
HRAG MARGOSSIAN
Master Thesis at KTH
Supervisor: Robert Eriksson Examiner: Mehrdad Ghandhari
XR-EE-ES 2010:008
Abstract
The aim of the project is to revise the load flow and dynamic PSS/E models of the Gotland network and validate them against a set of measurements collected during a major disturbance, a three phase short circuit in the 70 kV system.
The main task in revising the model is to convert the induction machine models of the wind turbines into user and manufacturer wind turbine models. The validation of the model is divided into two phases. The first is to use the measurements as well as some assumptions on the wind power generation and load distribution from the time of the fault to validate the dynamic behaviour of the system. The second is to use new measurements during a normal operation day. The latter would not be very helpful to illustrate the dynamic behaviour of the system, because of the lack of a major fault that would drastically affect the system, but it would nevertheless be useful to validate the load flow with greater accuracy.
Key Words: PSS/E, Gotland, Dynamic simulation of power system, model validation
Acknowledgements
I am very thankful to my supervisor at KTH, Robert Eriksson and my thesis examiner, Mehrdad Ghandhari for their constant support and guidance throughout the span of this project.
It is a pleasure to thank my supervisors at Vattenfall: Urban Axelsson and Daniel Wall, who went out of their ways to help me in every step of the project and without whom this thesis would not have been possible.
I would also like to show my gratitude to Per-Olof Lindström, who in more than one occasion helped me through some difficult situations with PSS/E, to all the people working at the R&D department at Vattenfall who made working there a truly enjoyable experience and to all the people at GEAB who provided me with as much information as they could to make the validation process a success.
Finally, I would like to dedicate this thesis to my parents and my sister for their unconditional love and support without which it would have been impossible for me to come this far.
Hrag Table of Contents
1 INTRODUCTION 1
1.1 Background 1 1.2 Project Organization 1 1.3 Project Tasks 1 1.4 Introduction to PSS/E 2 1.5 Prior Work 2 1.6 The Gotland Network 3 1.7 Report Structure 4 The report structure is as follows: 4 1.7.1 Chapter 2 – Validating the Dynamic Behaviour of the Model 4 1.7.2 Chapter 3 – Validating the Load Flow Model 5 1.7.3 Chapter 4 – Conclusions and Future Work 5
2 VALIDATING THE DYNAMIC BEHAVIOUR OF THE MODEL 7
2.1 Wind Turbines in Gotland 7 2.1.1 Wound Rotor Induction Generator Model with Variable Resistance 8 2.1.2 Doubly Fed Induction Generator Model 9 2.1.3 Full converter Turbines 11 2.1.4 Danish Concept Turbines 12 2.1.5 Vestas V47 Turbines 14 2.1.6 Vestas V90 Turbines with FRT 14 2.1.7 Kenersys Turbine 15 2.2 Wind Power Generation and Load Distribution 16 2.3 Capacitive Banks 19 2.4 The Three phase Fault 20 2.4.1 The fault 20 2.4.2 Clearing of the fault 23 2.4.3 Disconnection of 2 Transformers in Näs2 25 2.4.4 Disconnection of 2 Lines in Storugns 27 2.4.5 Opening of Breaker that disconnects HVDC converter at Näs 28 2.4.6 Wind Turbines disconnection 29 2.4.7 Load Disconnection 29 2.4.8 Summary of Events 30 2.5 Results of the Simulation 31 2.5.1 Comparison with Measurements 32 2.5.2 Fault Location 35 2.5.3 Disconnection Time of HVDC Light in Näs 39 2.5.4 Load Disconnection at Cementa 40 2.5.5 Frequency Analysis of the System 42 2.5.6 Conclusion 46 3 VALIDATING THE LOAD FLOW MODEL 48
4 CONCLUSION AND FUTURE WORK 51
BIBLIOGRAPHY 52
List of Tables Table 1: Gotland Regions...... 16 Table 2: Lines Separating Regions...... 16 Table 3: Pgen-Pload for all Regions ...... 18 Table 4: Status of Capacitor Banks ...... 19 Table 5: Arc Resistance Calculation ...... 23 Table 6: Three-Phase Fault Event List ...... 30 Table 7: Load Flow Validation ...... 49
List of Figures Figure 1: The Gotland Power Network ...... 3 Figure 2: WRIG with Variable Resistance Control ...... 8 Figure 3: Block Diagram for WRIG with Variable Resistance Control Model ...... 9 Figure 4: DFIG ...... 10 Figure 6: Full Converter ...... 11 Figure 5: Block Diagram of DFIG Model ...... 11 Figure 7: Block Diagram for Full Converter Model ...... 12 Figure 8: DCIG ...... 13 Figure 9: Block Diagram for DCIG Model ...... 14 Figure 10: Grid Code Curve ...... 15 Figure 11: Dividing Gotland into Regions ...... 17 Figure 12: Fault Location ...... 21 Figure 13: Line L8_S1 Configuration ...... 22 Figure 14: Fault Conditions for Calculating Rarc ...... 23 Figure 15: Voltage at Hemse (Breaker Times) ...... 24 Figure 16: Current out of the Transformer in Näs2 ...... 25 Figure 17: Voltage at the 10kV side of the transformer in Näs2 ...... 25 Figure 18: Unipower diagram for voltage at Näs2 (10 kV) ...... 26 Figure 19: Current in Line2 in Storugns ...... 27 Figure 20: Current in Line1 in Storugns ...... 27 Figure 21: Näs1 substation ...... 28 Figure 22: Current Flowing through Transformer Connected to HVDC Light ...... 28 Figure 23: Measurements Used for Validation ...... 31 Figure 24: Voltage at Hemse (meas. vs results) ...... 32 Figure 25: Voltage at Storugns (meas. vs results) ...... 33 Figure 26: Voltage at Bäcks (meas. vs results) ...... 34 Figure 27: Multiple Source Line ...... 35 Figure 28: The Infeed Effect ...... 36 Figure 29: Fault Locations - Sensitivity Analysis ...... 36 Figure 30: Voltage at Hemse (Fault Locations) ...... 37 Figure 31: Voltage at Storugns (Fault Locations) ...... 38 Figure 32: Voltage at Bäcks (Fault Locations) ...... 38 Figure 33: Voltage at Hemse (HVDC Disconnection) ...... 39 Figure 34: Voltage at Hemse (Cementa Load) ...... 40 Figure 36: Voltage at Storugns (Cementa Load) ...... 41 Figure 35: Voltage at Bäcks (Cementa Load) ...... 41 Figure 37: Frequency Variation (meas. vs results) ...... 42 Figure 38: Frequency Variation (commutation failure) ...... 43 Figure 39: Voltage at Hemse (Commutation Failure) ...... 44 Figure 40: Voltage at Bäcks (Commutation Failure) ...... 45 Figure 41: Voltage at Storugns (Commutation Failure) ...... 45 Figure 42: Load Flow Validation ...... 48
List of Appendices # of Pages
Appendix 1: Wind Turbine PSS/E Model Distribution 1 Appendix 2: Control Diagrams for PSS/E Library Wind Turbine Model Components 7
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1 Introduction
1.1 Background
In order to develop a reliable model, based on which key decisions can be made, the model needs to be validated. Studying the model in critical scenarios is the best way to accomplish this. In power systems however, performing controlled experiments to collect measurements can be very costly and therefore not a viable option, which is why it is very important to have measurements from real time faults.
The Gotland power network, owned by GEAB, is expected to undergo some major changes due to a substantial increase in the amount of installed wind power; it is thus very important to have an accurate model of the network that would allow for reliable simulations of the future system. Measurements taken during a recent major three phase short circuit in the 70 KV system, provide a unique opportunity to validate the PSS/E model.
1.2 Project Organization
The following master thesis project was carried out at Vattenfall Research and Development AB, under the supervision of Urban Axelsson and Daniel Wall.
The project was also supervised by Robert Eriksson in the Electric Power Engineering department at the Royal Institute of Technology (KTH). The project was assessed by the examiner, Professor Mehrdad Ghandhari.
Work on the project started on the 12th of January 2010 and continued till the end of June of the same year.
1.3 Project Tasks The tasks that were expected to be completed during the course of this project were:
• To modify the load flow and dynamic PSS/E models of the Gotland network.
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• To validate the model using two sets of measurements. First by using the measurements from the three phase fault to validate the dynamic behaviour of the system and then by measurements during no a windy, normal operation day, to validate the load flow model.
Each of these tasks will be studied in details in the later chapters of the report.
1.4 Introduction to PSS/E Power System for Engineering (PSS/E) is the major tool used in the course of this project. It is made of a set of programs for studies of power system transmission and generation behaviour in steady state and dynamic situations. It can be used as a tool to analyze the power flow and the related network functions, the optimal power flow, balanced and unbalanced faults, network equivalent construction, as well as dynamic simulation, see PSS/E User Manual [1].
1.5 Prior Work
At the start of the project, the following were made available:
Load flow file: provided by GEAB that includes all the nodes, lines, loads, capacitor banks and machines connected in the Gotland network. The main modifications required in this file are:
• To change The wind power generation and load values to correspond to the scenario of the fault • To connect/disconnect capacitor banks based on their status at the time of the fault. • To lump the wind turbines that were connected at the time of the fault according to the node they are connected to and the technology they are based on.
Dynamic file: used in prior projects that includes models for the HVDC Light, HVDC classic link, loads and wind generators. The main modification required in this file is to change the basic induction generator models used for the wind generators into more detailed wind turbine models.
For similar work on Gotland, see Persson [2] and Brask [3]
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1.6 The Gotland Network
The Gotland power network is isolated from the mainland by an HVDC classic link and the generation on the island is mainly restricted to wind power. The network includes 1 generator that can produce up to 8 MW of active power and 3 synchronous compensators that are used to control the frequency. An HVDC light link connects the wind heavy south of Gotland, at Näs, to the load heavy north at Bäcks. A simple overview of the network can be seen in Figure 1.
HULTUNGS STORUGNS
MARTEBO HELLVI
SLITE BÄCKS
YGNE KÄLLUNGE
ROMA
ESKELHEM KRÄKLINGBO
KLINTEBYS
GARDA STENBRO HEMSE Node
AC Line HAVDHEM NÄS I HVDC Light
Classic HVDC Link NÄS II Synchronous Compensator ÖJA
Figure 1: The Gotland Power Network
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Note that the figure also shows the major wind power generation areas: Näs and Havdhem in the south and Storugns/Hellvi in the north, as well as the largest load areas: Slite (Cementa factory) and Visby (the largest city in Gotland).
1.7 Report Structure
The report structure is as follows:
1.7.1 Chapter 2 – Validating the Dynamic Behaviour of the Model
Chapter 2 of the report explains in detail the process of the validation of the dynamic behaviour of the model and includes the following sections:
• Wind Turbines in Gotland: This section talks about the different wind turbines connected in Gotland at the time of the fault as well as the different wind turbine models used in PSS/E
• Wind Power Generation and Load Distribution: This section shows the process of estimating the wind power generation and load at each node in the system, at the time of the fault.
• Status of Capacitive Banks: In this section, another parameter needed for the fine tuning of the network to the situation of the fault is discussed: the capacitor banks connected.
• The Three Phase Fault: This section describes the characteristics of the three phase faults and describes the process of estimating the times of the different events that occur during the fault.
• Results of the Simulation: In the final section of this chapter the results of the simulations are presented. The voltages at three nodes are studied and sensitivity analysis on several of the parameters is performed. Finally the frequency response of the system is studied and a conclusion is drawn about the validation of the dynamic behaviour of the PSS/E model.
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1.7.2 Chapter 3 – Validating the Load Flow Model
Chapter 3 of the report explains in detail the process of the validation of the load flow model and explains why such a validation was carried out separately from the validation of the dynamic behaviour discussed in Chapter 2.
1.7.3 Chapter 4 – Conclusions and Future Work
In the final chapter of the report, some concluding remarks are made about the project and several points are suggested for future studies.
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2 Validating the Dynamic Behaviour of the Model
The first phase of validating the PSS/E model of the Gotland network is to use the measurements obtained during the three phase fault that was mentioned in Section 1.1 and that is explained in details in Section 2.4. The following chapter describes the different aspects of this validation.
2.1 Wind Turbines in Gotland
At the time of the fault, 144 wind turbines, ranging from 0.15 to 3 MW, were operational, with a total capacity of 95.285 MW. These turbines are divided into 21 different models, and distributed to the different nodes of Gotland.
For each node, the wind turbines were lumped together according to the availability of wind turbine PSS/E models. This amounted to 36 machines in PSS/E distributed to the different nodes (this distribution can be found in Appendix 1).
7 PSS/E models were made available. 4 of the models are generic PSS/E models:
• Wound rotor induction generator model with variable resistance control
• Doubly fed induction generator model
• Generator model connected to the grid via the power converter
• Directly connected induction generator model
The other 3 models are manufacturer models and are listed as follows:
• Vestas V47 model
• Vestas V90 model with FRT implemented
• Kenersys turbine model
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In what follows, each of these models is briefly explained and the turbines they were used for are specified. For more detailed explanation of these generic models see PSS/E Wind Model Library [4].
2.1.1 Wound Rotor Induction Generator Model with Variable Resistance
Optislip turbines have been modelled using the PSS/E standard model for wound rotor induction generators with variable resistance control (WT2):
Figure 2: WRIG with Variable Resistance Control
This generic model uses the following components:
• WT2G (generator/converter model): This model is based on the CIMTR3 model for induction generators, with consideration for rotor flux dynamics. At the start of the simulation, the model calculates the reactive power consumption based on the terminal voltage and active power dispatch and then places a “hidden shunt” on the bus to which the machine is connected with size equal to Qgen-Qcalculated. It also calculates the portion of the external rotor resistance needed to reach steady state.
• WT2E (electrical control model): Based on the rotor machine speed and the active power output, it calculates the portion of the available external rotor resistance to be added to the internal rotor resistance, during the simulation (the control diagram of this model can be found in Appendix 2).
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• WT12T (wind turbine model): It calculates the speed deviations of the rotor on the machine and on the blade sides (the control diagram of this model can be found in Appendix 2).
• WT12A (pseudo governor model): uses the blade rotor speed deviation and the real power at rotor terminals to get the mechanical torque on the rotor blade side that is used by WT12T (the control diagram of this model can be found in Appendix 2).
The interaction of these 4 models can be illustrated by the block diagram seen in Figure 3.
Figure 3: Block Diagram for WRIG with Variable Resistance Control Model
This model was thus used for all optislip turbines except for Vestas V47 turbines for which a manufacturer model was made available.
2.1.2 Doubly Fed Induction Generator Model
No manufacturer models for optispeed turbines without fault ride through (FRT) were available. The PSS/E user model for doubly fed induction generators with active control by a power converter connected to the rotor terminals (WT3) was thus used:
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Figure 4: DFIG
The user model uses the following components:
• WT3G (generator/converter model): This model calculates the required injected current into the network in response to the flux and active current output of the electrical control model. Flux dynamics have been eliminated to ensure a fast response to higher level commands from the electrical controls through the converter (the control diagram of this model can be found in Appendix 2).
• WT3E (converter control model): This model calculates the active and reactive power to be delivered to the system. Three modes of reactive power control are made available, constant reactive power, constant power factor angle or voltage regulation (the control diagram of this model can be found in Appendix 2).
• WT3T (wind turbine model): This model includes a simplified aerodynamic model that calculates the mechanical power and uses that to calculate the shaft speed (the control diagram of this model can be found in Appendix 2).
• WT3P (pitch control model): It calculates the blade pitch angle that is used by the wind turbine model (the control diagram of this model can be found in Appendix 2).
• WT3PLT: It is only used to set up output channels to plot results of dynamic simulations.
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The interaction of these models is illustrated in block diagram seen in Figure 5.
Figure 5: Block Diagram of DFIG Model
2.1.3 Full converter Turbines
Full converter turbines without FRT found in the system (mostly Enercon turbines) have been modelled using the standard PSS/E generic model for generators connected to the grid via the power converter (WT4):
Figure 6: Full Converter
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The different components of the model are:
• WT4G (generator/power converter module): This model calculates the injected current into the grid based on the active and reactive power outputs of the electrical control module (the control diagram of this model can be found in Appendix 2).
• WT4E (electrical control module): It performs reactive and active power control calculations. The control can be chosen among remote bus voltage control, power factor control and reactive power control. Active power control keeps the power balance between the machine and the grid injection. No machine simulation is used (the control diagram of this model can be found in Appendix 2).
The interaction of the two models is illustrated as a block diagram in Figure 7.
Figure 7: Block Diagram for Full Converter Model
2.1.4 Danish Concept Turbines
Danish concept turbines have been modelled using the standard PSS/E generic model for directly connected induction generators (WT1):
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Figure 8: DCIG
The different components of the model are:
• WT1G (generator/ converter model): It is based on the induction generator model CIMTR3 and takes into account the rotor flux dynamics. When the dynamic simulation is initialized, it calculates the reactive power consumption of the machine based on the terminal voltage and the active power dispatch. It then places a hidden shunt on the bus that the machine is connected to, with a rating equal to the difference between the specified Qgen and the calculated Q.
• WT12T (electrical control module): It calculates the speed deviations of the rotor on the machine and on the blade sides (the control diagram of this model can be found in Appendix 2 and is the same as that for the WRIG with variable resistance model).
• WT12A (pseudo governor model): Models the aerodynamic characteristics and pitch control of the turbine and calculates the aerodynamic torque (the control diagram of this model can be found in Appendix 2 and is the same as that for the WRIG with variable resistance model).
The interaction of the different components is illustrated as a block diagram in Figure 9.
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Figure 9: Block Diagram for DCIG Model
2.1.5 Vestas V47 Turbines
As mentioned in Section 2.1.2, all optislip turbines were modelled by the standard PSS/E model for wound rotor induction generators with variable resistance control, except for Vestas V47 turbines for which a manufacturer model was made available. In total 23 such turbines were operational during the time of the fault, distributed among 6 nodes. For more information on the details of the model, the reader should refer to the model datasheet.
2.1.6 Vestas V90 Turbines with FRT
Doubly fed induction generator based wind turbines are very sensitive to grid disturbances because of using small converters and thus can only survive small voltage dips. For this reason, the ride through ability is added to newer DFIG turbines so that they don’t disconnect until the fault is cleared. A widely utilized FRT system is the use of crowbars. Since the DFIG converter was designed to handle only a part of the total power, during disturbances, its apparent power capability is not sufficient to feed the power out to the grid thus low ohmic resistors (crowbars) are connected in order to drain energy from the system see Thiringer [5].
The FRT capability has become a must for many grid owners, who sometimes provide a low voltage curve that the wind generator is required to withstand, an example of this can be seen in Figure 10, see Tsourakis [6]. Royal Institute of Technology (KTH)
Figure 10: Grid Code Curve
The standard PSS/E DFIG model does not include this fault ride through capability. For that reason the V90 manufacturer model was used for those V90 turbines in the network that are equipped with FRT.
For more information on the details of the specific model provided by Vestas, the reader should refer to the VestasV90 model datasheet.
2.1.7 Kenersys Turbine
The kenersys turbine is based on the full converter technology and has the FRT capability. There is only one 2.5 MW kenersys turbine connected in the Gotland network, at Näs2. For details on the operation of the model, the reader is referred to the model datasheet.
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2.2 Wind Power Generation and Load Distribution
Unfortunately, accurate values for individual wind power generation and load levels at the time of the fault were not stored until the initialization of this project since relays retain the measurement data for only 90 days and it was 95 days after the fault that it was decided to initiate the project. Assumptions were thus made based on all the information available.
The total wind power generation and load at the time of the fault were known to be 37 and 100 MW respectively. To be able to choose values for the generation and load at different nodes, all the available power flow measurements on ac lines were studied; this allowed dividing Gotland into five regions, as seen in Table 1.
Table 1: Gotland Regions Region Nodes A Näs (I & II), Öja, Stenbro B Hemse, Havdhem C Hellvi, Storugns, Hultungs D Slite, Martebo E The rest of the nodes
The lines separating these regions are listed in Table 2.
Table 2: Lines Separating Regions Line Connecting Regions* Power Flow (MW) L41_S1 A to B 9.89 HVDC Light A to E 0.2 L8_S2 B to E 1.57 L2_S4 B to E 6.25 L1_S1 C to D 0.275 L6_S1 E to D 14.84 L7_S1 E to D 21.4 * The sequence is used to show the direction of the power flow at the time of the fault
A summary of this information can be seen in Figure 11.
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D
HULTUNGS C STORUGNS L6_S1: 14.84 MW MARTEBO HELLVI
SLITE From mainland: BÄCKS
KÄLLUNGE
YGNE ROMA
ESKELHEM
E KRÄKLINGBO
KLINTEBYS HVDC Light:
GARDA L8_S2: 1.57 MW STENBRO HEMSE
HAVDHEM B NÄS I Node
Area Boundary NÄS II Inter-Area Flow ÖJA L41_S1: 9.89 MW Area Letter
A
Figure 11: Dividing Gotland into Regions
Based on the above information (in addition to the fact that it is known that the transmission on the classic HVDC link from the mainland was 61.63 MW) it is possible to calculate the power going in or out of each region. This would be the same as the difference between the generation and load in that region:
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Table 3: Pgen-Pload for all Regions Region Pgen Pload (MW) A 9.89 B -2.07 C 0.275 D -36.515 E -33.41
Typical load and wind generation values were then used as a basis to estimate the load and generation values at the time of the fault such that the conditions in Table 3 as well as those for total load and generation are satisfied.
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2.3 Capacitive Banks
A list of the capacitor banks connected at the 11 kV level at the time of the fault was provided by GEAB and can be seen in Table 4.
Table 4: Status of Capacitor Banks ode MVAr Status Hultungs 1.5 ON Fårö 0.75 OFF Storugns 2.7 OFF Kräklingbo 1.5 ON Garda 1.5 OFF Roma 2.25 ON Eskelhem 1.5 OFF Stenbro 0.75 ON Havdhem 0.75 ON Öja 0.75 ON Näs2 1.5 ON* Pilhagen 2.25 OFF Elverket_T1 4.5 ON Elverket_T2 4.5 OFF Bingeby 4.5 OFF Länna 5.4 ON Bäcks 2.25 OFF Skrubbs 5.4 OFF Källunge 1.8 ON Klintebys 2.25 ON* Hemse 2.25 OFF *were triggered on after the fault
Optislip and DCIG turbines require reactive power support but no information on these capacitors at the 690V level was available and thus an assumption was made to connect capacitors, with ratings equal to 1/3rd the rating of the turbines, at buses where these turbines are connected. The measurement values of the reactive power consumption of the different turbines, provided by GEAB, resulted in a power factor of almost 1 for all turbines, even those that use the optislip and DCIG technology. It was thus assumed that these measurements were made to include the capacitors connected to the turbines. To make sure that the reactive power produced by the
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capacitors is not counted twice, the values for the Qgen of the different machines were set to the measured Qgen – the rating of the capacitor.
2.4 The Three phase Fault
A lightning storm caused a three phase short circuit on the 70 kV line connecting Ygne to Klintebys. This triggered a series of events in the network. A list of these events was sent by GEAB, but the times specified for these events were not synchronized. This can be explained either by the fact that the relays that registered these events were not synchronised among themselves or that different media access techniques were used to collect the information from the relays and the time registered in the events list is the time when the information reached the SCADA system and not the time the relays registered the events.
Of course to be able to simulate the fault correctly, the time for each event needs to be identified accurately. For this purpose, measurements on buses or lines closest to the location of each event were studied. The following events are discussed in this section:
• The fault
• Clearing of the fault
• Disconnection of 2 transformers in Näs2
• Disconnection of 2 lines in Storugns
• Opening of breaker that disconnects HVDC converter at Näs
• Wind turbine disconnection
• Load disconnection
2.4.1 The fault
The time of the fault is specified as 0 and will be used as a reference for the rest of the event times henceforth.
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According to the information sent by GEAB, the location of the fault was determined by a distance relay in Hemse that showed the distance to the fault to be 36.7 km. Fgure 12 illustrates the location of the fault.
Ygne
10.87 km
Eskelhem
14.605 km
Klintebys Hemse
18.3 km 36.7 km
Figure 12: Fault Location
The location of the fault can thus be calculated to be 7.076 km from Ygne. The impedance of the line from Ygne to Eskelhem is then divided in between the two sections on both sides of the fault.
Note that the distance relay at Hemse does not take the current from the local generation at Klintebys into account and thus the distance to the fault might not be very accurate. A more detailed analysis of this fact as well as a sensitivity analysis on the effect of changing the distance on the voltages at the different nodes is carried out in Section 2.5.2.
To simulate the fault, it is important to calculate the fault resistance. In a three phase fault such as this, the main resistance to consider is the arc resistance that depends primarily on the fault current and on the length of the arc. There are several models available for the calculation of the arc resistance derived from experiments. Such models include the Westinghouse AC arc model, the Neugebauer arc model and Warrington AC arc model; for literature on all three, see Lindahl [7]. The latter of the three models shall be used in this project.
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For fault currents less than 1000 A, the arc resistance is calculated, according to the model as: 28707 ∗ = . Where: Rarc is the arc resistance in ohms L is the length of the arc in m I is the arc current in A But for fault currents greater than 1000 A, the former formula is no longer valid, the following formula is to be used instead:
1804 ∗ =
The fault current and the arc length are needed. To calculate the length of the arc, the configuration of the line where the fault occurred is studied:
arc estimate
3.6 m
Figure 13: Line L8_S1 Configuration
The length of the arc can thus be estimated to be:
3.6 = = 5.655 2
The fault current changes when one side of the fault is tripped, consequently, the arc resistance also changes. The diagrams in Figure 14 illustrate the two fault conditions.
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Ygne Ygne
Figure 14: Fault Conditions for Calculating Rarc
The network is thus simulated two times, once with the breaker on the Ygne side closed and another where it is open. The results of the simulation as well as calculations of the arc resistance are seen in Table 5.
Table 5: Arc Resistance Calculation I L R Breaker closed 6250 5.654867 1.632221 Breaker open 1735.5 5.654867 5.878064
2.4.2 Clearing of the fault
To clear the fault, two events are triggered. First the protection on the line connecting Ygne to Klintebys opens the breaker on the Ygne side but the breaker on the Klintebys side fails to open. Instead, after a period of time, the breaker on the line connecting Klintebys to Hemse opens on the Hemse side.
Since both these events have a significant impact on the entire network, it is easy to extract the time at which they happen, looking at any of the measurements. The measurements of voltage in Hemse are used in this case:
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1.2
1
0.8
0.6 0.14s 0.62s Voltage (pu) 0.4
0.2
0 0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 Time (s)
Figure 15: Voltage at Hemse (Breaker Times)
The opening of the breakers is expected to cause a sharp increase in the voltage with a significant increase in the case of the second breaker since that means the fault is cleared. Two such increases are noticed in the plot, at times 140 ms and 620 ms. The fault is both severe and extends over a significant period of time, thus making it ideal for model validation.
Note that the times of the events have been identified in the Figure 15, with red arrows and this shall also be the case for the rest of the events described in this chapter.
During the simulations in PSS/E, while tripping the line to Hemse, the regions in Klintebys and Eskelhem would become like an island. It is thus important to also disconnect all the buses that become isolated from the rest of the system, since an island operation might cause the program to crash.
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2.4.3 Disconnection of 2 Transformers in Näs2
Figures 16 and 17 show the timeplots for the voltage and current out of the 10 KV side of one of the transformers:
300
250
200
150
Current (A)Current 100
50
0 0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 Time (s)
Figure 16: Current out of the Transformer in Näs2
8000
7000
6000
5000
4000
Voltage(v) 3000
2000
1000
0 0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 Time (s)
Figure 17: Voltage at the 10kV side of the transformer in Näs2
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Unfortunately the available data is not from the start of the fault and thus it is not clear when the transformer is disconnected, but the voltage waveform was available as a screenshot where it is measured from the start of the fault:
Figure 18: Unipower diagram for voltage at Näs2 (10 kV)
From Figure 16 and 17 it is possible to identify the moment when the transformer is disconnected and by comparing it to Figure 18, the exact time can be identified to be 370 ms after the fault.
An event log sent from the Näs2 substation showed that the two transformers were disconnected at the same time and thus the disconnection of the second transformer is also estimated at 370 ms.
Similar to the case when the fault is cleared, disconnecting each of these transformers leaves some buses isolated from the rest of the system and it is important to disconnect them during simulation to avoid a crash in the program.
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2.4.4 Disconnection of 2 Lines in Storugns
The event list shows two lines being tripped in Storugns. Studying the current in these lines (Figure 19 & 20) shows that both lines trip at around 370 ms. Since the 10 kV network is not modelled in PSS/E, the tripping of these lines can be simulated as disconnecting machines connected to these lines.
180 160 140 120 100 80 t=0s Current (A)Current 60 t=0.37 40 s 20 0 0.00 0.20 0.40 0.60 0.80 1.00 1.20 Time (s)
Figure 20: Current in Line1 in Storugns
90 80 70 t=0s 60 50 40 Current (A)Current 30 t=0.37s 20 10 0 0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 Time (s)
Figure 19: Current in Line2 in Storugns
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2.4.5 Opening of Breaker that disconnects HVDC converter at Näs
The time that this breaker was opened was not registered during the fault. To be able to estimate this time, the current in all lines going out of Näs 1 were studied. The adjacent figure is an overview of the Näs 1 station.
Thus to get the time at which the breaker seen in the figure opens, the currents through L41_S3 and out of the 70 KV side of the transformer are subtracted from the current through line L41_S2. The instantaneous values of the 3 recordings were summed up Figure 21: Näs1 substation based on the direction of current flow and then the rms of the result was calculated and can be seen in the figure below.
1200
1000
800 t=0.2s 600 t=0.3s
Current(A) t=0s 400
200
0 0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00 Time (s)
Figure 22: Current Flowing through Transformer Connected to HVDC Light Royal Institute of Technology (KTH)
Three major changes in the graph can be noticed. The first is at 140 ms, which is the time the breaker on the Ygne side was opened, the other two are at 200 and 300 ms respectively. Since no further information is available on how the HVDC converter was disconnected, both these times are possible. In what follows, 300 ms is taken as the time the breaker was opened, as that is the time when the current goes down to zero, but in Section 2.5.3, a study is made on the effect of taking the breaker opening time 200 ms instead.
It is important to note that HVDC light disconnecting at Näs right before the converter means the converter at Näs is isolated from the rest of the system. For a correct dynamic behavior of the model, the control mode for converter 2 (at Näs) should be switched to passive net operation; otherwise it could cause a crash in the program.
2.4.6 Wind Turbines disconnection
No information was available on the disconnection of individual turbines, but wind turbines are not able to survive 600 ms faults unless they have the FRT capability. Since the lines at Storugns and the transformers at Näs2 are disconnected at 370 ms, this shall also be the time chosen for disconnecting all wind turbines without FRT.
2.4.7 Load Disconnection
The load at Cementa was reduced from 34 MW at the start of the fault to 1.5 MW after it. No information however is available on when the load is actually disconnected. Based on numerous simulations, 140 ms has been estimated as the time for disconnection. A study on the effect of not disconnecting the load at Cementa is made in Section 2.5.4.
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2.4.8 Summary of Events
Table 6 summarizes the events list:
Table 6: Three Phase Fault Event List Event Time Three phase fault on line connecting Ygne to Klintebys 0 Circuit breaker trips on Ygne side 140 ms Cementa load is disconnected HVDC light is disconnected at Näs right before the 300 ms converter 2 transformers in Näs2 are disconnected 370 ms All wind turbines without FRT are disconnected Circuit breaker of trips on Hemse side 620 ms
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2.5 Results of the Simulation
In this section, the voltage at three different nodes in the network is studied for validating the model against the measurements; these are: Hemse (70kV), Bäcks (11kV) and Storugns (11kV). The reason these three nodes were chosen, is because clear voltage measurements are available for them and the nodes are geographically diverse allowing for a more comprehensive analysis. The location of the three nodes as well as the fault can be seen in Figure 23.
STORUGNS HULTUNGS
MARTEBO HELLVI
SLITE BÄCKS
KÄLLUNGE
YGNE ROMA
ESKELHEM
KRÄKLINGBO KLINTEBYS
GARDA STENBRO HEMSE Node
AC Line HAVDHEM NÄS I HVDC Light Classic HVDC NÄS II Measurement ÖJA Fault Location
Figure 23: Measurements Used for Validation
In addition to presenting the results and comparing them to the measurements, sensitivity analysis is made for several of the parameters that were chosen based on assumptions. These include:
• Fault location • Disconnection time of HVDC Light converter in Näs • Load disconnection at Cementa
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2.5.1 Comparison with Measurements In the following section, a comparison is made between the measurements and the simulation results for each of the three nodes.
2.5.1.1 Voltage at Hemse
1.2
1
0.8
0.6 Measurement Voltage (pu) Simulation Result 0.4
0.2
0 0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 Time (s)
Figure 24: Voltage at Hemse (meas. vs results)
Looking at the graph, the following observations are made:
• At t=0s, when the fault is introduced, the voltage drop that follows in the simulation seems to be sharper than the drop seen in the measurement. A probable explanation for this is that the physical fault did not start as a three phase fault but rather progressed into one, this however is not possible to simulate in PSS/E where the fault simulated is three phase and symmetric.
• In the period between 200 ms and 300 ms, there seems to be a slight difference between the two curves. One parameter that seems to affect this is the time at which
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the HVDC converter at Näs is disconnected. This will be further analyzed in Section 2.5.3. • After 620 ms (time at which the fault is cleared by the opening of the breaker at Hemse), there seems to be an obvious discrepancy between the measurement and the simulation results. The voltage increases to a value above what is seen in the measurements and then it drops to a slightly lower steady state. Looking at the measurement curve, it appears as though an event occurs at around 630 ms that causes a sudden drop in the voltage at the three nodes. It is however not possible to predict the nature of the event, because of the lack of additional information.
2.5.1.2 Voltage at Storugns
1.2
1
0.8
0.6 Measurement Voltage (pu) Simulation Result 0.4
0.2
0 0 0.5 1 1.5 2 Time (s)
Figure 25: Voltage at Storugns (meas. vs results)
Looking at the graph, the following observations are made:
• The voltage drop that follows the introduction of the fault has the same characteristics as the one seen at Hemse. However, in addition to the sharp voltage drop, the voltage also drops to a value lower than that observed in the measurement. After studying the different parameters, it was revealed that the exact location of the
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fault on the line connecting Ygne to Klintebys could have a significant impact on this; this impact is further studied in Section 2.5.2.
• After the first breaker is opened (at 140 ms), the voltage recovery seems to be slower than in the measurements. One factor that affects this is the disconnection of loads. In the simulated case, the load at Cementa was disconnected at 140 ms, but without the disconnection, the recovery would have been even slower, thus it is possible that there were other loads that were disconnected. The effect of the disconnection of the load at Cementa is studied in more detail in Section 2.5.4. Another factor that could play an important role in the voltage recovery is the transient behavior of the PSS/E model for the HVDC light converters, which could be reacting too slow compared to how it reacts physically, however with no measurements on the HVDC light, this cannot be confirmed or refuted.
• Finally, the same observation can be made for voltage profile at Storugns after the opening of the breaker at Hemse (at 620 ms) as for the voltage profile at Hemse.
2.5.1.3 Voltage at Bäcks
1.2
1
0.8
0.6 Measurement Voltage(pu) 0.4 Simulation Result
0.2
0 0 0.5 1 1.5 2 Time (s)
Figure 26: Voltage at Bäcks (meas. vs results)
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The same observations can be made for the voltage profile at Bäcks as for the voltage profile at Storugns. However, from 300 ms to 600 ms, the voltage at Bäcks seen in the results of the simulation is lower than the actual measurement, something that is not seen as clearly in Storugns. It is not clear if fixing the voltage recovery would also fix this problem. This could be a sign of some missing components in the model (maybe capacitive banks) or perhaps the misbehavior of one of the models; unfortunately with the lack of additional measurements, it was not possible to pinpoint where the problem lied. In terms of network behavior, this could mean that an analysis of the results would suggest that some undervoltage protection relays would trip in certain situations even though they would not in the physical network (for example, looking at Figure 26, we would falsely predict undervoltage protection relays that are set to trip for voltages below 0.8 pu and after 300 ms to trip at Bäcks).
2.5.2 Fault Location
As mentioned in Section 2.4.1, the location of the fault based on the distance relay estimate might not be very accurate. To better explain the reason behind this margin of error, the operation principle of the distance relays is studied.
For a line, like that connecting Ygne to Klintebys, that is fed from both sides (refer to Figure 24), the measured impedance at one side of the line by the distance relay can be interpreted as:
= + + 1 Where RF is the fault resistance, I is the measured current contribution at the location of the relay and Ir is the current contribution from the other side of the line. Zline is the impedance from the location of the relay to the point of the fault and is the ratio of the voltage to the current seen at the location of the distance relay, see Urresty [8].
Z<
I Ir
Figure 27: Multiple Source Line
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But in the case of the calculation of the fault distance in the Gotland network, it was made at Hemse, and not at Klintebys, and thus there is an infeed (due to the wind turbines connected at Klintebys). This effect is illustrated in Figure 28.
Klintebys Ygne
Z<
I Ir Iinfeed Hemse
Figure 28: The Infeed Effect
The impedance seen by the distance relay is not the actual impedance from the point of measurement to the fault since there is a third current contribution that is not taken into consideration by the relay. Since there is an infeed current coming from Klintebys, the distance given by the relay is an overestimation (If there was an outfeed current, the distance would have been underestimated), see Alexander [9]
An inaccurate fault location means wrong values for the arc resistance, which could affect the simulation results. A sensitivity analysis was thus performed to study this effect. The voltages at the three nodes were studied by considering the fault to be at Eskelhem, Ygne or the location specified by the distance relay (refer to Figure 29 to see the three locations considered):
Ygne
Eskelhem
Klintebys Hemse
Figure 29: Fault Locations - Sensitivity Analysis
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The resulting graphs can be seen in Figures 30 to 32 seen below:
1.2
1
0.8 measurement
0.6 Fault at Ygne Voltage (pu) 0.4 Fault at Location Estimated by Distance Relay Fault at Eskelhem 0.2
0 0 0.5 1 1.5 Time (s)
Figure 30: Voltage at Hemse (Fault Locations)
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1.2
1
0.8 measurement
0.6 Fault at Ygne Voltage (pu) 0.4 Fault at Location Estimated by Distance Relay
0.2 Fault at Eskelhem
0 0 0.5 1 1.5 Time (s)
Figure 31: Voltage at Storugns (Fault Locations)
1.2
1
0.8 measurement
0.6 Fault at Ygne Voltage (pu) 0.4 Fault at Location Estimated by Distance Relay Fault at Eskelhem 0.2
0 0 0.5 1 1.5 Time (s)
Figure 32: Voltage at Bäcks (Fault Locations)
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Studying the three graphs it seems choosing the fault location as that specified by the distance relay is the best option for the voltage profile at Hemse but choosing it at Eskelhem would fit best for Storugns and Bäcks. The fault can thus be estimated to be located somewhere in between Eskelhem and the location calculated by the distance relay. Note that this agrees with the previous expectation of the location of the fault having been overestimated by the distance relay.
The location of the fault seems to have a considerable effect on the voltage at Hemse after the disconnection of the breaker at Ygne but before the disconnection at Storugns and Bäcks.
2.5.3 Disconnection Time of HVDC Light in Näs
In Section 2.4.5, it was stated that the exact time of the disconnection of the HVDC Light converter in Näs is not clear and two probable times were identified. The difference in taking the two times as compared to the measurements is studied. Only the graph for Hemse is included since the effect on the voltage profiles at Storugns and Bäcks (which are located in the north of Gotland as opposed to Hemse and Näs) is not noteworthy.
1.2
1
0.8
0.6 Measurement
Voltage (pu) HVDC at 300 ms 0.4 HVDC at 200 ms
0.2
0 0 0.5 1 1.5 2 Time (s)
Figure 33: Voltage at Hemse (HVDC Disconnection)
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Disconnecting the HVDC Light converter in Näs at 200 ms provides better correspondence between the measurement and simulation result than disconnecting it at 300 ms; with the absence of any further sources of information, it can be assumed that 200 ms is the correct time for the disconnection.
2.5.4 Load Disconnection at Cementa
The load at Cementa decreases from 34 MW before the fault to 1.5 MW after it, but no information on the time of the disconnection is available. The following section studies the effect of not considering any load disconnection on the results of the simulation.
1.2
1
0.8
measurement 0.6 cementa load disconnected Voltage (pu)Voltage at 140ms 0.4 cementa load not disconnected 0.2
0 0 0.5 1 1.5 Time (s)
Figure 34: Voltage at Hemse (Cementa Load)
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1.2
1
0.8 measurement 0.6 cementa load disconnected Voltage (pu) 0.4 at 140ms cementa load not 0.2 disconnected
0 0 0.5 1 1.5 Time (s)
Figure 35: Voltage at Bäcks (Cementa Load)
1.2
1
0.8 measurement 0.6 cementa load disconnected at Voltage (pu) 0.4 140ms cementa load not disconnected 0.2
0 0 0.5 1 1.5 Time (s)
Figure 36: Voltage at Storugns (Cementa Load)
Without disconnecting the load at Cementa, the voltage seems to recover more slowly especially in Storugns and Bäcks which are geographically closer to Cementa than Hemse. This can be explained by the fact that the load at Cementa would draw reactive power from the system and hinder voltage recovery. It is thus acceptable to Royal Institute of Technology (KTH)
assume that the load is disconnected around the same time (or slightly before) the disconnection of the first breaker at Ygne.
2.5.5 Frequency Analysis of the System
The graph seen in Figure 37 shows a comparison between the simulation results and measurements obtained for the frequency of the system at Storugns since this was the only node where a measurement for frequency was available. 52 51.5 51 50.5 50 49.5
49 measurement
Frequency(Hz) 48.5 simulation Result 48 47.5 47 46.5 0 0.5 1 1.5 Time (s)
Figure 37: Frequency Variation (meas. vs results)
As seen in the figure, the frequency response of the simulation is slower than in the measurements. Possible explanations for this are:
• The models for the synchronous machines in the system (NG.14, NG.13 and NG.11) do not react transiently fast enough.
• The frequency regulator is not as accurate for long duration faults as for less severe faults or cases of load disconnection or generation disconnection that have been studied earlier, see Persson [3].
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• Commutation failure happens in the HVDC link, something which is not included in the PSS/E model of the link.
While studying the accuracy of the models for the synchronous machines and the frequency regulator are beyond the scope of this project, a further study into the commutation failure of the HVDC link was carried out.
Commutation failure is a possible malfunction in the converter of the HVDC link due to a fault in the AC side that causes severe voltage drops. It results in an interruption of the power flow.
Since no measurements are available for the transmission on the HVDC link, the HVDC has been disconnected and reconnected at different times during the fault and the effect on the frequency of the system as well as the voltage at the different nodes is studied.
52
51
50 measurement
49 no disconnection
Frequency (Hz)Frequency 48 disconnecting at 0.25s and Reconnecting at 0.62s 47 Disconnecting at 0s and Reconnecting at 0.62s 46 0 0.2 0.4 0.6 0.8 1 1.2 1.4 Time (s)
Figure 38: Frequency Variation (commutation failure)
Looking at Figure 38, it can be seen that the frequency profile seems to look better when we consider the HVDC link to have undergone commutation failure; nevertheless the rate at which the frequency decreases is too high and the frequency ends up dropping to 47 Hz instead of 48Hz (for the case when the HVDC is disconnected at 250ms).
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One explanation for this is that disconnecting the HVDC link and reconnecting it after the fault is cleared might not be a good way of modeling the commutation failure; Once the HVDC link is disconnected, and the first breaker at Ygne opens, the voltage at the connection point of the link rises above 0.8 pu, which means commutation failure would stop but at this point when the HVDC link is reconnected, the voltage drops again and thus the HVDC link will need to be disconnected in the simulation once more and this process continues and is not easy to simulate in PSSE without commutation failure being implemented in the HVDC link model itself.
It is important to note that the difference between simulation results and the measurements seen in Figure 37 could be the result of a combination of the possible explanations previously mentioned in this section, but without any additional measurements or information, it is not possible to give a definite conclusion. Although the simulation of the commutation failure by disconnecting the link and reconnecting it after the fault is cleared is not necessarily accurate, it is nevertheless interesting to study the voltages at the different nodes for such a simulation:
1.2
1
0.8 measurement 0.6 no disconnection Voltage (pu) 0.4 Disconnecting at 0.25s and Reconnecting at 0.62s 0.2
0 0 0.5 1 1.5 Time (s)
Figure 39: Voltage at Hemse (Commutation Failure)
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1.2
1
0.8 measurement 0.6 no disconnection Voltage (pu) 0.4 Disconnecting at 0.25s and 0.2 Reconnecting at 0.62s
0 0 0.5 1 1.5 Time (s)
Figure 40: Voltage at Bäcks (Commutation Failure)
1.2
1
0.8 measurement 0.6 no disconnection Voltage (pu) 0.4 Disconnecting at 0.25s and 0.2 Reconnecting at 0.62s
0 0 0.5 1 1.5 Time (s)
Figure 41: Voltage at Storugns (Commutation Failure)
The impact of the HVDC link disconnection on the voltages at the three nodes does not seem to be significant. The voltage profiles seem to improve slightly especially after the clearance of the fault and reconnection of the HVDC link.
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2.5.6 Conclusion Despite the uncertainties surrounding the different parameters that make up the scenario for which the model is validated, it is nevertheless clear that the model behaves in accordance with the real life system. The only factor that seems to vary significantly is the frequency; possible reasons for this have been explained in Section 2.5.5. Further studies are suggested to ensure a better frequency response of the model. Another thing that needs to be looked into in more details is the voltage recovery in the north of Gotland that seems to be slower than what has been observed in the measurements, whether this is due to missing or misbehaving components in the network model needs to be identified.
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3 Validating the Load Flow Model It was explained in Section 2.2 of this report that the wind power generation and load values used for simulating the fault scenario were chosen so as to make sure that the flows on certain lines correspond to the available measurements. This however means that it was not possible to validate the model in what concerns the flows on the different lines based on the results of these simulations. For that reason, a second set of measurements were taken at an instant during a windy day with high load and normal system operation and then system was simulated for the conditions of that instant. The results are illustrated in Figure 42 below.
HULTUNGS STORUGNS
MARTEBO 1.1 HELLVI 1.1 9.8 37.4 10 7.5 15.9 SLITE 30 BÄCKS 7 16 KÄLLUNGE 11 19 YGNE ROMA 10 18 19 13.4 ESKELHEM 16 13 19.6 KRÄKLINGBO 18
KLINTEBYS 15.7 16 16.5
15 GARDA 29.9 19.1 STENBRO 29.3 Node HEMSE 19 AC Line 29 10.8 HAVDHEM HVDC Light NÄS I 28.1 10.9 25.9 Classic HVDC Link NÄS II 25.9 123 simulation result ÖJA 123 measurement
Figure 42: Load Flow Validation
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The most noticeable differences between the load flow simulation results and the measurements are summarized in Table 7:
Table 7: Load Flow Validation Line Simulation Result Measurement Hemse to Klintebys 16.5 15 Klintebys to Ygne 19 16 Roma to Kallunge 19 18 Ygne to Bäcks 37.4 30 Ygne to Roma 11 10
It was confirmed by GEAB that the differences seen at the Ygne substation, can be explained by faulty transducers. The differences in the other lines are relatively smaller and might be explained by the fact that most measurements available seem to be rounded to the nearest integer. Another factor that may have affected the results is the modeling of the transmission losses in the system and the fact that no load losses for transformers are not considered in the model.
Nevertheless, the distribution of the power in between the lines for this high load, high production scenario seems to be in accordance with the measurements and the load flow model can thus be considered reliable.
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4 Conclusion and Future Work
The results seen in Chapters 2 and 3 show that the behaviour of the model seems to correspond well with the real time measurements, however there were several factors that hindered the validation process and should be considered for future validations. These include:
• The wind power production and load values were not recorded accurately for all the nodes in the network. This was mainly due to the fact that recordings are stored in the relays for only 90 days and thus in case of future faults, it is important to retrieve them before that time.
• The measurements taken during the fault were not enough and this limited the analysis that could be made in several areas. In the future, measurements should be taken for as many power flows and node voltages as possible, in addition to frequency measurements and measurements on important components in the system such as the synchronous compensators, the HVDC light converters and the HVDC classic link.
• The times of the different events on the event list were not synchronized, this lead to the need to estimate the times based on available measurements which were in some cases not enough.
It is also important to study the transient responses of several components in the model, such as the synchronous compensators and the HVDC light converters to make sure that they react fast enough in severe fault situations as that studied in Chapter 2.
Finally, the PSS/E model for the HVDC link needs to be revised in order to account for commutation failure.
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Bibliography
[1] Siemens Power Technologies International, “PSS/E Users Manual”, PSSE/ 31.0, December 2007.
[2] Siemens Power Technologies International, “PSS/E Wind Model Library”, pp 29-50 (56), January 2009.
[3] J. Persson, Vattenfall Research and Development AB, U-NE, “Uppgradering av N tmodellen F r Gotland I PSS/E”, June 2009.
[4] M. Brask, Vattenfall Research and Development AB, U-NE, “Modelling of the Power System of Gotland in PSS/E with Focus on HVDC Light”, April 2008.
[5] T. Thiringer, J. Paixao & M. Bongiorno, Elforsk, “Monitoring of the Ride-Through Ability of a 2 MW Wind Turbine in Tvååker, Halland”, pp 10-11 (88), February 2009.
[6] G. Tsourakis & C. D. Vournas, National Technical University of Athens, “Simulation of Low Voltage Ride Through Capability of Wind Turbines with Doubly Fed Induction Generator”, pp 1 (9), March 2009.
[7] S. Lindahl, “Effect of Geomagneticaaly induced currents on protection systems”, p. 157-159 (345), December 2003.
[8] C. Gallego, J. Urresty, & J. Gers, IEEE, “Analysis of Phenomena that Affect the Distance Protection”, pp 1 (7), 2008.
[9] G. E. Alexander & J. G. Andrichak, GE Power Management, “Application of Phase and Ground Distance Relays to Three Terminal Lines”, pp 1-2 (17).
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Appendix A
Wind Turbine PSS/E Model Distribution
PSSE Bäcks Garda Havdhem Hellvi Hultungs Klint. Kräklingbo Källunge model WRIG with Rvar 0 1200 1450 6000 0 0 0 0 V47 660 0 2640 2640 0 660 0 660 DFIG 0 0 7650 0 0 0 0 0 DCIG 0 450 0 0 0 490 200 150 Full Coverter 0 0 0 1000 1000 500 0 500 Kenersys 0 0 0 0 0 0 0 0 V90 with FRT 0 0 0 0 0 0 0 0
PSSE Länna Martebo Näs 1 Näs 2 Roma Sten. Storugns Öja model WRIG with Rvar 600 825 0 11150 0 600 225 0 V47 0 0 0 3960 0 0 3960 0 DFIG 0 0 0 4160 0 0 4500 0 DCIG 0 650 5530 8640 150 1730 55 2500 Full Coverter 0 0 0 1000 0 0 2700 0 Kenersys 0 0 0 2500 0 0 0 0 V90 with FRT 0 0 9000 3000 0 0 0 0
Appendix B
Control Diagrams for PSS/E Library Wind Turbine Model Components
Note that all the diagrams illustrated in this appendix are taken excerpts from the PSS/E Wind Model Library and I have not contributed in any way in their development.
WRIG with Variable Resistance WT2E:
WT12T:
WT12A: Doubly Fed Induction Generator Model WT3G:
WT3E:
WT3T:
Wind Turbine Module for the Single Mass Mechanical System
Two Mass Torsional Module
WT3P:
*The pitch Control and Pitch Compensation integrators are non-windup integrators as a function of the pitch, i.e. the inputs of these integrators are set to zero when the pitch is in limits (Pmax or Pmin) and the integrator input tends to force the pitch command further against its limit. The outputs of these integrators are not limited except by the lower (zero) limit on the Pitch Compensation integrator.
Directly Connected Induction Generator Model WT4G:
WT4E: