Implementation and Validation of the Nordic TestSystem in DIgSILENT PowerFactory

Luis David Pabon OspinaAndres Felipe Correa

Department of Power System Control and DynamicsFraunhofer IWESKassel, Germany

luis.david.pabon.ospina@iwes.fraunhofer.de

Gustav LammertDepartment of Energy Management and

Power System OperationUniversity of Kassel

Kassel, Germanygustav.lammert@uni-kassel.de

Abstract—This paper presents the implementation of theNordic test system in DIgSILENT PowerFactory. The imple-mented system is a variant of the Nordic32 network and isbased on the technical report “Test Systems for Voltage StabilityAnalysis and Security Assessment” prepared by the IEEE PowerSystem Dynamic Performance Committee, the Power SystemStability Subcommittee, and the Test Systems for Voltage Stabilityand Security Assessment Task Force. This work deems all ofthe implemented controllers and validates the PowerFactoryimplementation against the original model presented in the afore-mentioned technical report. It is shown through RMS simulationsthat the action of load tap changers and over excitation limitersare leading forces through a long-term voltage collapse andtherefore, their accurate modeling is crucial. Furthermore, theimplemented system can be whether downloaded from the IEEEPES Power System Dynamic Performance Committee website orrequested directly to the authors.

Index Terms—Dynamic security assessment, long-term voltagestability, Nordic 32 test system, voltage collapse.

I. INTRODUCTION

The Nordic test system is a variation of the so-calledNordic32 system, which was created in order to illustrate thevoltage collapse in Sweden that happened in the year 1983[1]. It has been proposed by the CIGRE Task Force 38-02-08 in 1995 [2] and it is a fictional approximation of theSwedish system that along with other network models wasproposed in order to assess the performance of simulationtools and provide researchers with benchmarks to develop theLong-Term Dynamics field. Nevertheless, the system is notlimited to long-term phenomena, its applicability to short-term dynamics such as transient stability and small-signaloscillatory angle stability is recognized. From its very firstappearance on, the Nordic test system has been used not onlyfor software testing purposes but also for other sort of dynamicstudies such as short-term and long-term voltage stability,power system restoration, system protection and small-signalstability studies among many others. In [2], it is shown throughRMS simulations carried out using PSS/E and EUROSTAGthe impact of Over Excitation Limiters (OELs) and Load TapChangers (LTCs) on the long-term voltage collapse. In [1],the Nordic32 test system is used in order to investigate powersystem restoration issues. In [3], a modified version of the

Nordic32 system which includes induction motor loads is usedto investigate the delayed voltage recovery after system faults.In [4], a coordinated decentralized emergency voltage andreactive power control to prevent long-term voltage instabilityis proposed and its effectiveness is proven on the Nordic32test system. In [5], an algorithm which prevents undesirabledistance protection operations that might result during voltageinstability periods is tested on the Nordic32 power system. In[6], the Nordic32 system is simplified in a 5 busbar test systemnamed N5area in which the key voltage collapse characteristicsof the Nordic32 are reflected in order to test in a less complexnetwork so the actions of load recovery and excitation currentlimiters are easier to simulate. In [7], small-signal stability isassessed using the Nordic32. In [8], a procedure to identify theonset of long-term voltage instability from the time evolutionof the distribution voltages controlled by LTCs is proposedand demonstrated using the Nordic32 test system.

Due to its particular characteristics, the Nordic test systemhas shown a growing demand for different kinds of powersystem stability studies. Therefore, the IEEE Power SystemDynamic Performance Committee provides in [9] input datafor different software tools including RAMSES [10], PSS/E,and ANATEM. DIgSILENT PowerFactory is a widely usedcommercial power system analysis software, especially inEurope and South America. Numerous transmission and dis-tribution system operators as well as research institutes anduniversities use this software simulation tool [11]. In order toserve the need of academia and industry, the new contributionof this paper is the implementation and validation of theNordic test system in DIgSILENT PowerFactory. Furthermore,the implemented system can be whether downloaded from theIEEE PES Power System Dynamic Performance Committeewebsite or requested directly to the authors.

II. SYSTEM DESCRIPTION

The Nordic test system depicted in Fig. 1 consists of 4 areas:an equivalent simplified network that has the biggest genera-tors and therefore serves usually as the system reference, thenorthern region with few load and more generation, a centralarea with more load than generation and a southern regionloosely connected to the rest of the system. The test network

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reuse of any copyrighted component of this work in other works.DOI: 10.1109/PTC.2017.7980933

CSSynchronouscondenser

71

4071 4011

g9

1011

11

g20

1013

g2

13

g3

1014

12

1012

g1g11

4012

g10

g5

4072

72

g19

1021 1022

4031g4 2032 203122

4022g12

NORTH

4021

4032

400 kV220 kV130 kV

42

4042

g144043 4046

43 46g6

4044

1044

CENTRAL

31g8

32

4041

41g13 g7

40613 4

1043

61

2 47g15

4047

1042

51g16

4051

40455

10451041

1

g1762

63g18

4062

4063

SOUTH

EQUIV.

CS

Fig. 1. Nordic test system - single line diagram [12].

is composed by 32 transmission buses with nominal voltagesof 400 kV, 220 kV and 130 kV. Additionally, 22 buses are ata distribution level with a voltage of 20 kV and 20 generatornodes with a voltage of 15 kV.

There are basically three kinds of transformers involved inthis power system, the 20 step-up transformers convert thegeneration voltage of 15 kV into the transmission voltage thatcan be 400 kV, 220 kV or 130 kV according to the regionlevel. Eight transformers convert the voltage among the threedifferent already mentioned transmission voltage levels. The22 step-down transformers are placed for distribution dutiesand hence their function is to convert the transmission voltagelevel into the distribution level for the loads at 20 kV. All ofthe transformers neglect the copper losses and the magnetizingsusceptance.

The reactive power management is helped by a total of 11shunt elements out of which nine are capacitors and two arereactors. The Equivalent grid has one shunt reactor, while theNorth region has one reactor and one capacitor, the Southregion doesn’t have any sort of shunt compensation at all,leaving the Central region which has to cope with significantpower transfer from the North with the eight remaining shuntcapacitors.

All loads are connected to 20 kV buses and are representedby an exponential model which behavior is described asfollows:

P = P0

(V

V0

)α(1)

Q = Q0

(V

V0

)β(2)

being α = 1 (constant current) and β = 2 (constantimpedance). V0 assumes the voltage at initial conditions ofthe bus to which the load is connected.

The Nordic test system makes use of hydro and thermalgeneration. Out of the total of 20 generators, the Equivalentand the North networks have hydro generation that is modeledby salient-pole machines. The two biggest generators belong tothe Equivalent grid while the North area has 10 generators. Onthe other hand, there are seven thermal generators modeled byround-rotor machines, two of them belong to the small Southregion and the remaining five to the Central one that alsohas a synchronous capacitor that is modeled as a salient-polemachine.

The models for the above listed power system elementsare detailed enough for long-term as well as for short-termstability studies. A complete system description can be foundin [12].

III. IMPLEMENTATION OF THE DYNAMIC MODELS

All the dynamic models such as Automatic Voltage Regu-lators (AVRs), Power System Stabilizers (PSSs), Over Excita-tion Limiters (OELs), Load Tap Changers (LTCs) and speedgovernors are described in detail in [12]. This section focusesspecially on those which implementation can vary from onesoftware tool to another.

A. Automatic voltage regulator, over excitation limiter andpower system stabilizer

The model depicted in Fig. 2 is used to represent the AVR,the PSS and the OEL. The PSS is present in all of thegenerators with the exception of the two big generators ofthe Equivalent grid and the synchronous capacitor. A first-order system represents the exciter and the AVR also includesa transient gain reduction chosen to limit the overshoot interminal voltage following a step change in voltage referencewhen the generator operates in open circuit. The PSS is formedby a washout filter with two cascaded leads which providedamping for oscillation frequencies from 0.2 Hz to more than1 Hz.

There is more than 3 GW of power transfer from North toCentral area and the maximum power that can be delivereddepends mostly on the reactive power capabilities of theCentral area. The reactive power limits are defined by theOELs. This system presents long-term voltage instability giventhat the maximum power that can be delivered is smallerthan the one that LTCs aim to restore in some contingencyscenarios.

The OELs are one of the leading forces through a long-term voltage collapse. In this particular case their effect can beeasily observed when one of the transmission lines connecting

C

+ vfdG(1+ sTa)1+ sTb

Vo

+

+

ilimfd

ifd

1s

1+ sT11+ sT2

1+ sT11+ sT21+ sTw

L1

f

1

r

00.1

L21s

timer

+

y 0

C

transient

exciter

power system stabilizer

2 3

y

y

Min

V

ω Kps

gain reduction

10

0

1

10

Fig. 2. Model of Exciter, AVR, PSS and OEL [12].

the North zone with the Central zone is tripped. After suchevent, LTCs act to restore distribution voltages and henceload consumption. The generators are forced to increase theirreactive power injection in order to keep the voltage at theset-point value. When the field current exceeds for a certaintime the current limit denoted as ilimfd and equal to 105% of therated field current iratedfd , the OEL sets the field current to ilimfd .The above mentioned time depends on the parameters L1, fand r in Fig. 2. Without an accurate modeling of the OEL thelong-term voltage collapse to be described in Section V willsignificantly differ from the one in [12].

B. Speed governor and hydro turbine

The nominal frequency of the system is 50 Hz and iscontrolled by the speed governors (see Fig. 3) of the hydrogenerators, the thermal generators of the Central and Southarea are not involved in frequency control and for the explainedreasons in [12], constant mechanical torque is assumed for themachines of thermal plants. The model of the speed governorincludes a simple power measurement, a PI control and aservomotor represented by a first-order system with a timeconstant of 0.2 s and non-windup limits on z which representsthe gate opening.

The speed governor gives the gate opening to the hydroturbine model depicted in Fig. 4, which is represented by asimple lossless model with a water time constant Tw of 1 s.In this model q represents the water flow, H the head, Pm themechanical power and Tm the mechanical torque.

1 σ

P o11+ s2

5.02.0

servomotor

PI control+

+

+ z0.1

0.1

1

0

1s

+

+

0.4

ω

1s

P +

+

Fig. 3. Model of speed governor [12].

+ Pm(

qz

)2

s

1Tw

Tmω

s

1

1z

qH

H

Fig. 4. Model of hydro turbine [12].

C. Load tap changer

All distribution transformers are equipped with LTCs keep-ing the distribution voltage in the deadband [0.99 - 1.01] p.u.The LTCs adjust the transformer ratios in the range [0.88 -1.20] over 33 positions (thus from one position to the next,the ratio varies by 0.01) [12].

The LTCs have intentional delays. When the distributionvoltage leaves the above deadband at time t0, the first tapchange takes place at time t0+τ1 and the subsequent changesat times t0 + τ1 + kτ2 (k = 1, 2, ...). The delay is reset to τ1after the controlled voltage has reentered to (or jumped fromone side to the other of) the deadband [12]. The values of τ1and τ2 are given in [12] and differ from one transformer toanother in order to avoid unrealistic tap synchronization.

The implementation of the LTC control was addressed inthis work with a simple state machine shown in Fig. 5, whichcontrol logic is explained in Table I.

D. Saturation

The generator’s main-flux saturation is another issue to beconsidered. Small mismatches on the saturation characteristiclead to events shifted in time in a long-term voltage collapsewhen compared with the original system. The main reason isthat the OELs will limit the field current at different times ifsaturation is not considered or if it differs from the one in[12].

z01

z12

z21

z00z00

e0

e1e2

Fig. 5. State machine for the implementation of the LTC control.

TABLE ILTC STATE MACHINE CONTROL LOGIC.

Transition Condition Action

z00 V returns to or jumps the dead band e=0z01 e=0 and V is out of dead band for τ1 s e=1 and tap stepz12 e=1 and V is out of dead band for τ2 s e=2 and tap stepz21 e=2 and V is out of dead band for τ2 s e=1 and tap step

In this work, the saturation characteristic is as it is depictedin Fig. 6.

Vnl [p.u.]

1.0

1.2

1.0 i1.0

Air-gap line

i1.2 ifd [p.u.]

A B C

Fig. 6. Implemented saturation characteristic.

According to [12], the saturation characteristic of all gen-erators in the Nordic test system is given by:

k =| AC || AB |

= 1 +m(Vnl)n (3)

in which, for Vnl = 1.0 p.u. k = 1.1 and hence m = 0.1, andfor Vnl = 1.2 p.u. k = 1.3 and hence n = 6.0257.

From (3), it can be derived that i1.0 = 1.1 p.u. andi1.2 = 1.56 p.u.

The implemented saturation characteristic is an exponentialfunction with the following input parameters:

SG10 =i1.0i0− 1 (4)

SG12 =i1.2

1.2 · i0− 1 (5)

where i0 = 1.0 and hence SG10 = 0.1 and SG12 = 0.3. Moredetails about the saturation model can be found in [13].

IV. STUDY CASES

In order to validate the implemented system and compare itagainst the results in [12], two different scenarios have beenconsidered.

A. Scenario 1

A solid three phase fault is applied to the bus 4032 witha subsequent opening of the line 4032-4044 without furtherre-connection. As stated in [12], the initial fault is simulatedjust to be more realistic, but it is actually the line outage thatcauses the long-term voltage collapse. The long-term behaviorwould be very similar without the initial three phase fault.

B. Scenario 2

The same disturbance as in Scenario 1 is applied. In thiscase, a corrective post disturbance control is implemented.This control is a typical System Integrity Protection Scheme(SIPS), which consist in decreasing the voltage set-point ofLTCs controlling the distribution voltage by 0.05 p.u. Due tothe load characteristics explained in (1) and (2), by decreasing0.05 p.u. the voltage set-point, the active power consumptionis expected to reduce 5%, while the reactive power approxi-mately 10%.

The corrective control takes place after the lowest transmis-sion voltage reaches 0.9 p.u. which is at 100 s of simulation.

Two different variants have been implemented:• Scenario 2a: reducing the set point of the five LTCs

controlling the distribution buses 1, 2, 3, 4 and 5.• Scenario 2b: reducing the set point of the 11 LTCs

controlling the distribution buses 1 to 5 in addition tothe buses 41, 42, 43, 46, 47 and 51.

V. RESULTS AND VALIDATION

A. Scenario 1

The results of the Scenario 1 are depicted from Fig. 7to Fig. 10. For all the figures in this paper, the originalresults taken from [12] correspond to solid lines, while thePowerFactory implementation ones correspond to the dashedlines.

The chain of events resulting in a voltage collapse runsas follows: a solid three phase fault is applied to the bus4032. The line 4032-4044 is tripped 0.1 s later. The system isshort-term stable, and it settles to a new equilibrium in 30 s.At around 35 s, the LTCs start acting attempting to restorethe distribution voltage and hence the load consumption. Theaction of the LTCs forces the generators to increase theirreactive power injection and therefore their field current asit can be seen in Fig. 8. Due to the actions of the LTCs, theOELs of the six generators in Fig. 8 limit the field current.Some other generators as the ones in Fig. 9 are not limited.It can be seen in Fig. 10 how the limited generators, as in thecase of g6 and g7, loose their capability to control voltage andtheir terminal voltage drops until the system finally collapses.

B. Scenario 2

Fig. 11 shows the evolution of the voltage magnitude ofthe transmission bus 1041 which is the one with the lowestvoltage. The action of reducing the voltage set-point of theLTCs controlling distribution voltages can be observed. Thefirst variation (Scenario 2a) of the post disturbance controlconsisting in reducing the above mentioned voltage set-pointby 0.05 p.u. shows that although the control action succeedsin reducing the power consumption, it is still more than whatcan be provided and the system finally collapses shortly before200 s.

On the other hand, the second variation (Scenario 2b), showsto be an effective emergency control as it is able to preventthe load restoration in a way that the voltage of transmissionbuses is recovered even to a higher value than the one priorthe disturbance. Due to the LTCs delays, the action of thispost disturbance control is slow but it succeeds restoring thetransmission voltage before 600 s without any under-voltageload shedding.

Note that the transmission voltages are recovered to valueseven higher than those before the disturbance. In fact, thisemergency control is possible due to the regaining voltagecontrol of the synchronous generators. As shown in Fig. 12, thegenerators which were limited in Fig. 8, recover their voltage

time [s]

0 20 40 60 80 100 120 140 160 180

Volta

geM

agni

tude

[p.u

.]

0.7

0.8

0.9

1.0

1.1

Bus 1041Bus 1042Bus 4012Bus 4062

Fig. 7. Voltage magnitude of affected buses – Original test system (solidlines) PowerFactory results (dashed lines).

time [s]

0 20 40 60 80 100 120 140 160 180

Fiel

dC

urre

nt[p

.u.]

1

2

3

4g06g07g11g12g14g15g16

Fig. 8. Field currents of seven limited generators – Original test system (solidlines) PowerFactory results (dashed lines).

time [s]

0 20 40 60 80 100 120 140 160 180

Fiel

dC

urre

nt[p

.u.]

1.5

2.0

2.5

3.0

g08g18g09

Fig. 9. Field currents of three non limited generators – Original test system(solid lines) PowerFactory results (dashed lines).

time [s]

0 20 40 60 80 100 120 140 160 180

Volta

geM

agni

tude

[p.u

.]

0.7

0.8

0.9

1.0 g6g7

Fig. 10. Terminal voltage of two limited generators – Original test system(solid lines) PowerFactory results (dashed lines).

control after some time avoiding thereby several over-voltagesin the transmission system.

VI. CONCLUSIONS

In this work, the Nordic test system described in the tech-nical document “Test Systems for Voltage Stability Analysisand Security Assessment” prepared by the Test Systems for

time [s]

0 100 200 300 400 500 600

Volta

geM

agni

tude

[p.u

.]

0.7

0.8

0.9

1.0

No action on LTCsVoltage setpoint reduction on 5 LTCsVoltage setpoint reduction on 11 LTCs

Fig. 11. Voltage magnitude at bus 1041 – Original test system (solid lines)PowerFactory results (dashed lines).

time [s]

0 100 200 300 400 500 600

Fiel

dC

urre

nt[p

.u.]

1

2

3

4

g06g07

g11g12

g14g15

g16

Fig. 12. Generator’s field currents with the implemented post disturbanceemergency control.

Voltage Stability and Security Assessment Task Force fromthe IEEE Power System Dynamic Performance Committee,was implemented in DIgSILENT PowerFactory. The resultsof the implemented system are validated against those inthe aforementioned report through RMS simulations. Resultsshow that the long-term voltage collapse phenomena can beobserved mainly because of the action of LTCs and OELs aftera system disturbance. A corrective post disturbance emergencycontrol was implemented and validated against the originalsystem, showing that it can avoid the long-term voltagecollapse. Furthermore, the implemented system can be whetherdownloaded from the IEEE PES Power System DynamicPerformance Committee website or requested directly to theauthors.

VII. OPEN SOURCE

The implemented Nordic test system model in DIgSI-LENT PowerFactory can be whether downloaded from theIEEE PES Power System Dynamic Performance Committeewebsite: http://ewh.ieee.org/soc/pes/psdpc/PSDP benchmarksystems.htm or requested directly to the authors.

The authors request, that the publications derived from theuse of the downloaded system explicitly acknowledge that factby citing this paper.

ACKNOWLEDGMENT

Due to their helpful feedback during the development ofthis work [14], [15], the authors would like to thank ThierryVan Cutsem from the Department of Electrical Engineeringand Computer Science at University of Liege - Belgiumand Past-Chair of the Power System Dynamic Performance

Committee, and Costas Vournas from the School of Electricaland Computer Engineering at the National Technical Univer-sity of Athens and Chairman of the IEEE Dynamic SecurityAssessment working group.

This research work was supported by the German FederalMinistry for Economic Affairs and Energy within the frame-work of the project Netz:Kraft (FKZ: 0325776A).

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[2] CIGRE - Task Force C38-02-08, “Long-Term Dynamics Summary PartII - A practical Assessment of Simulation Tools,” Tech. Rep., 1995.

[3] H. Khoshkhoo and S. M. Shahrtash, “Fast Online Dynamic Voltage In-stability Prediction and Voltage Stability Classification,” IET Generation,Transmission Distribution, vol. 8, no. 5, pp. 957–965, May 2014.

[4] S. R. Islam, D. Sutanto, and K. M. Muttaqi, “Coordinated DecentralizedEmergency Voltage and Reactive Power Control to Prevent Long-TermVoltage Instability in a Power System,” IEEE Transactions on PowerSystems, vol. 30, no. 5, pp. 2591–2603, Sept 2015.

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[9] IEEE Power & Energy Society Power System Dynamic PerformanceCommittee. “Benchmark Systems”. [Online]. Available: http://ewh.ieee.org/soc/pes/psdpc/PSDP benchmark systems.htm

[10] P. Aristidou, D. Fabozzi, and T. Van Cutsem, “Dynamic Simulation ofLarge-Scale Power Systems Using a Parallel Schur-Complement-BasedDecomposition Method,” IEEE Transactions on Parallel and DistributedSystems, vol. 25, no. 10, pp. 2561–2570, Oct 2014.

[11] G. Lammert, L. D. Pabon Ospina, P. Pourbeik, D. Fetzer, and M. Braun,“Implementation and Validation of WECC Generic Photovoltaic SystemModels in DIgSILENT PowerFactory,” in 2016 IEEE Power & EnergySociety General Meeting, Boston, July 2016, pp. 1–5.

[12] IEEE Task Force on Test Systems for Voltage Stability and SecurityAssessment, “Test systems for voltage stability analysis and securityassessment,” PES-TR19, Tech. Rep., August 2015.

[13] DIgSILENT GmbH, “DIgSILENT PowerFactory Synchronous MachineTechnical Reference Documentation,” Tech. Rep., 2016.

[14] T. Van Cutsem, Private letter with the authors, Aug. 2016.[15] C. D. Vournas, Private letter with the authors, Sep. 2016.