VALIDATION OF THE PSS/E MODEL FOR THE GOTLAND NETWORK611660/FULLTEXT01.pdf · 2013. 3. 18. · 1.4 Introduction to PSS/E Power System for Engineering (PSS/E) is the major tool used

The Royal Institute of Technology Department of Electrical Engineering Electric Power Engineering

VALIDATION OF THE PSS/E MODEL

FOR THE GOTLAND NETWORK

Master Thesis at KTH

Supervisor: Robert Eriksson

Examiner: Mehrdad Ghandhari

XR-EE-ES 2010:008

HRAG MARGOSSIAN

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

Royal Institute of Technology (KTH)

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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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HULTUNGS

HELLVI

STORUGNS

SLITE

MARTEBO

KÄLLUNGE

KRÄKLINGBO

GARDA

BÄCKS

YGNE

ESKELHEM

KLINTEBYS

ROMA

HEMSE

HAVDHEM

STENBRO

NÄS I

NÄS II

ÖJA

Node

AC Line

HVDC Light

Classic HVDC Link

Synchronous Compensator

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.

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


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):

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).

Figure 2: WRIG with Variable Resistance Control


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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


• 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.


The interaction of these models is illustrated in block diagram seen in Figure 5.

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

Figure 5: Block Diagram of DFIG Model


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 interaction of the two models is illustrated as a block diagram in Figure 7.

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):

Figure 7: Block Diagram for Full Converter Model


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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.


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].

Figure 9: Block Diagram for DCIG Model


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.

Figure 10: Grid Code Curve


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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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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:

HULTUNGS

HELLVI

STORUGNS

SLITE

MARTEBO

KÄLLUNGE

KRÄKLINGBO

GARDA

BÄCKS

YGNE

ESKELHEM

KLINTEBYS

ROMA

HEMSE

HAVDHEM

STENBRO

NÄS I

NÄS II

ÖJA

Node

L6_S1: 14.84 MW

L8_S2: 1.57 MW

L41_S1: 9.89 MW

From mainland:

HVDC Light:

A

C

B

E

D

Area Boundary

Inter-Area Flow

Area Letter

Figure 11: Dividing Gotland into Regions


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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

0ode 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.

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.

Eskelhem

Klintebys Hemse

36.7 km

10.87 km

14.605 km

18.3 km

Ygne

Figure 12: Fault Location


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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:

The length of the arc can thus be estimated to be:

� = 3.62 � = 5.655 �

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.

3.6 m

arc estimate

Figure 13: Line L8_S1 Configuration


Page 23 (52)

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:

Ygne Ygne

Figure 14: Fault Conditions for Calculating Rarc


Page 24 (52)

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.

0

0.2

0.4

0.6

0.8

1

1.2

0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6

Vo

lta

ge

(p

u)

Time (s)

0.14s 0.62s


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:

0

50

100

150

200

250

300

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8

Cu

rre

nt

(A)

Time (s)

Figure 16: Current out of the Transformer in Näs2

0

1000

2000

3000

4000

5000

6000

7000

8000

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8

Vo

lta

ge

(v

)

Time (s)

Figure 17: Voltage at the 10kV side of the transformer in Näs2


Page 26 (52)

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.


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.

0

20

40

60

80

100

120

140

160

180

0.00 0.20 0.40 0.60 0.80 1.00 1.20

Cu

rre

nt

(A)

Time (s)

t=0s

t=0.37

s

Figure 20: Current in Line1 in Storugns

0

10

20

30

40

50

60

70

80

90

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80

Cu

rre

nt

(A)

Time (s)

t=0s

t=0.37s

Figure 19: Current in Line2 in Storugns


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

based on the direction of current flow and

then the rms of the result was calculated and can be seen in the figure below.

Figure 21: Näs1 substation

0

200

400

600

800

1000

1200

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00

Cu

rre

nt

(A)

Time (s)

t=0.2s

t=0.3st=0s

Figure 22: Current Flowing through Transformer Connected to HVDC Light


Page 29 (52)

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.


Page 30 (52)

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

Cementa load is disconnected

140 ms

HVDC light is disconnected at Näs right before the

converter

300 ms

2 transformers in Näs2 are disconnected

All wind turbines without FRT are disconnected

370 ms

Circuit breaker of trips on Hemse side 620 ms


Page 31 (52)

HULTUNGS

HELLVI

STORUGNS

SLITE

MARTEBO

KÄLLUNGE

KRÄKLINGBO

GARDA

BÄCKS

YGNE

ESKELHEM

KLINTEBYS

ROMA

HEMSE

HAVDHEM

STENBRO

NÄS I

NÄS II

ÖJA

Node

AC Line

HVDC Light

Classic HVDC

Measurement

Fault Location

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.

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

Figure 23: Measurements Used for Validation


Page 32 (52)

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

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

0

0.2

0.4

0.6

0.8

1

1.2

0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6

Vo

lta

ge

(p

u)

Time (s)

Measurement

Simulation Result


Page 33 (52)

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

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

0

0.2

0.4

0.6

0.8

1

1.2

0 0.5 1 1.5 2

Vo

lta

ge

(p

u)

Time (s)

Measurement

Simulation Result


Page 34 (52)

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

Figure 26: Voltage at Bäcks (meas. vs results)

0

0.2

0.4

0.6

0.8

1

1.2

0 0.5 1 1.5 2

Vo

lta

ge

(p

u)

Time (s)

Measurement

Simulation Result


Page 35 (52)

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].

Figure 27: Multiple Source Line

Z<

Ir I


Page 36 (52)

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.

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):

Z<

Hemse

Klintebys Ygne

Ir I Iinfeed

Figure 28: The Infeed Effect

Eskelhem

Klintebys Hemse

Ygne

Figure 29: Fault Locations - Sensitivity Analysis


Page 37 (52)

The resulting graphs can be seen in Figures 30 to 32 seen below:

Figure 30: Voltage at Hemse (Fault Locations)

0

0.2

0.4

0.6

0.8

1

1.2

0 0.5 1 1.5

Vo

lta

ge

(p

u)

Time (s)

measurement

Fault at Ygne

Fault at Location Estimated

by Distance Relay

Fault at Eskelhem


Figure 31: Voltage at Storugns (Fault Locations)

0

0.2

0.4

0.6

0.8

1

1.2

0 0.5 1 1.5

Vo

lta

ge

(p

u)

Time (s)

measurement

Fault at Ygne


by Distance Relay

Fault at Eskelhem

Figure 32: Voltage at Bäcks (Fault Locations)

0

0.2

0.4

0.6

0.8

1

1.2

0 0.5 1 1.5

Vo

lta

ge

(p

u)

Time (s)

measurement

Fault at Ygne


by Distance Relay

Fault at Eskelhem


Page 39 (52)

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.

Figure 33: Voltage at Hemse (HVDC Disconnection)

0

0.2

0.4

0.6

0.8

1

1.2

0 0.5 1 1.5 2

Vo

lta

ge

(p

u)

Time (s)

Measurement

HVDC at 300 ms

HVDC at 200 ms


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.

0

0.2

0.4

0.6

0.8

1

1.2

0 0.5 1 1.5

Vo

lta

ge

(p

u)

Time (s)

measurement

cementa load disconnected

at 140ms

cementa load not

disconnected

Figure 34: Voltage at Hemse (Cementa Load)


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

0

0.2

0.4

0.6

0.8

1

1.2

0 0.5 1 1.5

Vo

lta

ge

(p

u)

Time (s)

measurement

cementa load disconnected at

140ms

cementa load not

disconnected

0

0.2

0.4

0.6

0.8

1

1.2

0 0.5 1 1.5

Vo

lta

ge

(p

u)

Time (s)

measurement

cementa load disconnected

at 140ms

cementa load not

disconnected

Figure 35: Voltage at Bäcks (Cementa Load)


Page 42 (52)

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.

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].

46.5

47

47.5

48

48.5

49

49.5

50

50.5

51

51.5

52

0 0.5 1 1.5

Fre

qu

en

cy (

Hz)

Time (s)

measurement

simulation Result


Page 43 (52)

• 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.

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).

46

47

48

49

50

51

52

0 0.2 0.4 0.6 0.8 1 1.2 1.4

Fre

qu

en

cy (

Hz)

Time (s)

measurement

no disconnection

disconnecting at 0.25s and

Reconnecting at 0.62s

Disconnecting at 0s and



Page 44 (52)

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:

Figure 39: Voltage at Hemse (Commutation Failure)

0

0.2

0.4

0.6

0.8

1

1.2

0 0.5 1 1.5

Vo

lta

ge

(p

u)

Time (s)

measurement

no disconnection

Disconnecting at 0.25s and



Page 45 (52)

Figure 40: Voltage at Bäcks (Commutation Failure)

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.

0

0.2

0.4

0.6

0.8

1

1.2

0 0.5 1 1.5

Vo

lta

ge

(p

u)

Time (s)

measurement

no disconnection



0

0.2

0.4

0.6

0.8

1

1.2

0 0.5 1 1.5

Vo

lta

ge

(p

u)

Time (s)

measurement

no disconnection




Page 46 (52)

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.


Page 47 (52)


Page 48 (52)

HULTUNGS

HELLVI

STORUGNS

SLITE

MARTEBO

KÄLLUNGE

KRÄKLINGBO

GARDA

BÄCKS

YGNE

ESKELHEM

KLINTEBYS

ROMA

HEMSE

HAVDHEM

STENBRO

NÄS I

NÄS II

ÖJA

Node

AC Line

HVDC Light

Classic HVDC Link 25.9

25.9

29

28.1

29.9

29.3

19.1

19

16.5

15

15.7

16

13.4

13

19.6

18

19

16

11

10

37.4

30 7.5

7

19

18

15.9

16

1.1

1.1 9.8

10

123 simulation result

123 measurement

10.8

10.9

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.

Figure 42: Load Flow Validation


Page 49 (52)

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.


Page 50 (52)


Page 51 (52)

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.


Page 52 (52)

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).

Appendix A

Wind Turbine PSS/E Model Distribution

PSSE model

Bäcks Garda Havdhem Hellvi Hultungs Klint. Kräklingbo Källunge

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 model

Länna Martebo Näs 1 Näs 2 Roma Sten. Storugns Öja

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:

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