CALCULATION OF THE FAULT LEVEL CONTRIBUTION OF DISTRIBUTED GENERATION ACCORDING TO IEC STANDARD 60909

TH. BOUTSIKA S. PAPATHANASSIOU∗ N. DROSSOS

National Technical University of Athens (NTUA) Public Power Corporation (PPC) Greece

Keywords: Short-Circuit Current (SC Current) - Fault Level - Distribution Network (DN) -

Distributed Generation (DG) 1. INTRODUCTION Distribution networks are characterized by a design short-circuit (sc) capacity, i.e. a maximum fault current to be never exceeded, related with the rating of switchgear and the thermal and mechanical endurance of all equipment and standardized constructions. Distributed generation (DG) resources are typically connected to distribution networks, at the low or medium voltage level, and therefore contribute to the total fault level of the network, roughly determined by the combined short-circuit contributions of the upstream grid and the various DG sources within the distribution network. Hence, a basic requirement for permitting the interconnection of DG is to ensure that the resulting fault level remains below the network design value, under the most unfavourable conditions. In traditional distribution networks, the upstream system sc contribution is already close to the design maximum value. Hence the fault level constraint is often one of the most significant reasons inhibiting the connection of large amounts of generation to existing distribution networks and imposing in practice the need for a reliable and efficient calculation of the expected fault level. In this paper, the methodology of latest edition of IEC Standard 60909 ([1-4]) is applied to distribution networks with DG resources, to determine the maximum fault level. IEC 60909 provides the basis for calculating the short circuit contribution of the upstream grid, while reasonable assumptions are made regarding the DG contribution. To illustrate its application, the methodology is applied to a study case MV network with a variety of DG sources.

∗ NTUA-Electric Power Division, 9 Iroon Polytechniou st., 15780 Athens, Greece. e-mail: st@power.ece.ntua.gr

2. APPLICATION OF THE IEC 60909 STANDARD 2.1. About the IEC 60909 Standard The IEC 60909 International Standard is applicable for the calculation of sc currents in three-phase a.c. systems operating at a nominal frequency of 50 or 60 Hz. Balanced (three-phase) and unbalanced faults are considered and, in both cases, maximum and minimum values of the sc currents are calculated. The sc current is considered as the sum of an a.c. symmetrical component and of an aperiodic (d.c.) decaying component. The Standard distinguishes between far-from-generator and near-to-generator (and motor) short-circuits. Moreover different approaches are provided according to network configuration – radial or meshed – and to fault location. For the calculation of the fault level, only the maximum sc currents need to be considered. In distribution networks with a radial operating configuration and a low-impedance grounded neutral, this typically requires the calculation of sc currents for three-phase, far from generator short-circuits. 2.2. The equivalent voltage source method The initial symmetrical short-circuit current kI ′′ is the r.m.s. value of the a.c. symmetrical component of a prospective sc current. The term initial symmetrical short-circuit power, kS ′′ , i.e. the fault level, stands for a fictitious value determined as the product of the initial symmetrical sc current and the nominal system voltage UkI ′′ n at the short-circuit location F:

nkk UIS ′′=′′ 3 (1)

The calculation method of IEC 60909 [1] determines the sc currents at location F using the equivalent voltage source, 3ncU , defined as the voltage of an ideal source applied at the short-circuit location in the positive sequence system, whereas all other sources in the system are ignored (short-circuited). All network feeders, synchronous and asynchronous machines are replaced by their internal impedances. When calculating maximum short-circuit currents, the voltage factor c may be assumed equal to cmax=1.1, for any voltage level of the network. The equivalent voltage source method is illustrated in Fig. 1.

Un

Q A

~Non-rotating load

~Non-rotating loadT

k3LVHVtr:1 F

L

~

ZQ ZTQ

ZL

3ncU

( )″=

++ kLTQ

n IZZZ

cU3

A F

Fig. 1. Illustration of the equivalent voltage source method.

In the case of balanced short-circuits the initial symmetrical sc current is calculated by

knk ZcUI 3=′′ (2)

where Zk is the magnitude of an equivalent short-circuit impedance Zk of the upstream grid (essentially its Thevenin impedance) at the short-circuit location F (see Fig.1). According to the equivalent voltage source method, it is possible to determine the short-circuit current at location F using only of the nominal voltage and the rated characteristics of

the equipment, although the application of certain correction factors is also deemed necessary [2]. In networks with different voltage levels, voltages, currents and impedances are converted to the voltage level of the short-circuit location using the rated transformation ratio tr of the transformers involved. 3. FAULT LEVEL CALCULATION IN DISTRIBUTION NETWORKS 3.1. General In distribution networks (with or without DG), the maximum fault level typically occurs at the busbars of the infeeding substation, due to the large contribution of the upstream grid, which is rapidly diminishing downstream the network. In the presence of DG, the resulting total fault level is the sum of the maximum fault currents due to: the upstream grid, through the network transformer and the various generators (and possibly large motors) connected to the distribution network.

Un

QNetworkfeeder

3-phase faultat the MV busbar

MVHVtr:1

F

UnQ

ANetworktransformer

Un

ReactorUnit transformer

MVHVtr:1

F LG3~

DG station

3-phase faultat the MV busbarof the substation

(a) (b) Fig.2. Contributions to the fault level in MV distribution networks (a) of the upstream grid

and (b) of a DG Stations 3.2. Contribution of the upstream grid The contribution of the upstream grid, depicted in Fig. 2a, is calculated by:

)(3)(3 2maxmax

TLVTrQ

n

KTQt

nk ZKtZ

UcZZ

UcI

+=

+=″ (3)

where ZQ is the impedance of the network feeder (upstream grid) at the connection point Q and ZT is the impedance of the transformer. KT is a correction factor used for the impedance of the transformer. The above quantities are calculated using the following relations1:

kQ

nQQ I

cUZ

′′=

3 (4)

rT

rTkrT S

UuZ2

%100⋅= , 2

2

3%100 rT

krT

rT

rTRrT I

PSUuR =⋅= , 22

TTT RZX −= (5)

TT x

cK6,01

95,0 max

+⋅= (6)

where is the initial symmetrical sc current at the HV connection point Q, ukQI ′′ kr is the short-circuit voltage of the transformer (in %), uRr is the rated resistive component of the short- 1 Subscripts r and n state rated and nominal values. Superscript b states the maximum known values in normal operation (before the short-circuit). Lower case letters for reactances stand for per unit values, expressed on the rated reactance of the equipment.

circuit voltage (in %)and PkrT are the load losses at rated current. A typical assumption is RQ/XQ=0.1, although higher values are often encountered. uRr decreases with the size of the transformer [3] and if not given, it may be ignored (uRr=0). 3.3. Contribution of the DG Stations DG stations connected to MV distribution networks are mostly wind turbines (WT) and small hydroelectric plants (SHEP). Other types of DG stations like photovoltaics, fuel-cells, micro-turbines and small scale cogeneration units are mostly connected to the LV level and their size is usually small enough not to create concern. Notably, IEC 60909 has been developed with no DG in view and for this purpose the contribution of the various DG types is not included in the Standard, nor in relevant literature (e.g. [5,6,7]). For instance, only induction motors are dealt with, whereas the parameter values of synchronous generators provided in [4] are applicable to conventional units of very large size. The fault contribution of DG stations depends on the generator type and technology (synchronous or induction, directly connected or interfaced to the grid via power electronic converters). For conventional generators, it is given by (see Fig. 2):

)(3max

RLTG

nk ZZZZ

UcI

+++=″ (7)

where the impedances of the generator (G), the transformer (T) (if any), the interconnection line (L) to the substation and the reactor (R) (if any) are included, all referred to the voltage at the short-circuit location F. For the generator impedance ZG the following apply: • For synchronous generators connected directly to the grid, the impedance and its correction

factor are given by: ''

dGG jXRZ += (8)

rGdrG

nG x

cUUK

ϕsin1 ''max

+⋅= (9)

where Xd” is the subtransient reactance of the synchronous machine, RG=0.15Xd

”can be used and KG is the applicable correction factor from IEC 60909. • For synchronous generators connected to the grid through a unit transformer, referred to as

power station units in the IEC Standard, the combined generator-transformer impedance and the relevant correction factor are given by:

THVGrS ZZtZ += 2 (10)

( ) ( )rGd

TrTHV

rTLV

GrG

nQSO x

cpUU

pUU

Kϕsin1

11 ''

max

+⋅±⋅⋅

+= (11)

with RG=0.15Xd”, whereas pG and pT may be ignored here (pG=pT=0). The impedance of the

transformer ZTHV is expressed at its HV side. • The impedance of asynchronous generators connected directly to the grid is calculated by:

rG

rG

rGLRrG

rG

rGLRG S

UIII

UII

Z21

31

⋅=⋅= (12)

with RG=0.1XG and a typical ratio of locked-rotor current to rated current of the machine ILR/IrG=8. If the asynchronous generator is interconnected through a transformer, the

impedance of the latter is calculated from eq. (5), using also the correction factor KT from eq. (6). Both impedances are referred to the HV side of the transformer2. For generators connected to the grid via power electronic converters the following relation applies, in place of eq. (7):

==″rGk kII ct (for time ∆t) (13)

i.e. the generator acts as a source of constant fault current, equal to k times the rated current of the generator, where ∆t is the maximum duration of the contribution, before the DG is disconnected by its own protection. If the DG includes a transformer, the current is converted to the voltage level of the fault location F. A typical value for the fault current may be k=1.5 (representing the short-time over-current capability of the grid-side converter), whereas ∆t will depend on the protection and fault ride-through capability of the DG unit. Nevertheless, ∆t is needed only for breaking and thermal current calculations. Doubly-fed induction generators (DFIG), extensively used in variable speed WTs, are a special case. Despite the presence of the converter in their rotor circuit, their fault current contribution resembles that of the directly connected induction generators. Hence, eq. (7) may be applied, using ILR/IrG=8 and RG=0.1XG for the generator impedance. The duration ∆t of their contribution, however, should be limited to 3-5 cycles. 4. CASE STUDY In Fig. 3 a MV study case distribution network is shown, fed from a 50 MVA HV/MV transformer. Four DG stations with a total power of about 17 MW are connected to the substation MV busbars by dedicated lines (three wind farms, each having six identical wind turbines, and one small hydroelectric plant consisting of three identical turbines). The data of the network and the equipment are given in Table 1. In Table 2, fault level calculation results are presented for a three-phase fault at the MV busbars of the substation. The following observations hold: The total fault level is 301 MVA (239 MVA due to the upstream grid and 62 MVA due to the DG stations). Wind farm 2 contributes about four times more current than wind farm 1, due to the different technology of the WTs. The reactor R at the output of wind farm 3 effectively reduces its contribution (without the reactor, the sc current of the wind farm would increase by more than 50%). With the reactor in place, wind farm 3 contributes less than wind farm 2, although its output power is higher.

Most important is the fact that the design fault level of such a distribution network would be around 250 MVA (HV/MV transformer with uk~20% @50 MVA). Hence, the connection of even a moderate amount of DG (17 MW in this case, which is realistic) drives the fault level to unacceptably high values.

2 The voltage factor cmax utilized in the calculation of correction factors is related to the rated voltage of the

equipment and not to the voltage at the short-circuit location. For the calculation of KG and KSO, sinφrG is positive for a leading power factor of the generator. The factor 1 ± pT represents the tap positions corresponding to the maximum and minimum transformation ratio, while pG is the permitted over-voltage at the generator terminals.

1 2 3 4

G1

T6

G6

T1

G3~

G3~

Un=400 V

L1 L2 L4

G7

T12

G12

T7

G3~

G3~

Un=20 kV

Un=690 V

G13

T18

G18

T13

G3~

G3~

UnQ=150 kV

Un=20 kV

T20T19

G3~

G3~

Un=690 V

L3

G20 G21

Un=20 kV

non -rotating loadsS=35 MVA

p.f .=0.85 lagging

Un=20 kV

Network Feeder

Network Transformer

F

Un=20 kV

G3~

G19

Wind farm 1

Wind farm 2

Wind farm 3

Small Hydroelectric Plant

3-phase fault at the MV busbar

of the substation HV

MVtr:1

Un=690 V

R

Fig. 3. Case study MV distribution network.

TABLE 1 - DATA OF THE CASE STUDY NETWORK

Network feeder kVU nQ 150= , S MVAkQ 3000=′′ , 1.0=QQ XR

Network T/F MVASrT 50= , %)22%,5.19( %5.20 === +− kkkr uuu , kWPkrT 160= , ( ) kVr 21150%5.17%5.12

−+=t

Wind farm 1 6 x 600 kW (G1-G6) generator synchronous with converter (G1-G6): kWPrG 600= ,U VrG 400= , AI rG 866=

transformer unit (T1-T6): ,kVASrT 630= kVtrT 4.0 20 %)5(±= , %4=krTu ,u %2.1=kRrT

line L1 overhead line (20kV): kmRL / 215.0 Ω= , kmX L / 334.0 Ω= , l km 101 = underground cable: kmRL / 162.0 Ω= , kmX L / 115.0 Ω= , l km 5.01 =

Wind farm 2 6 x 660 kW (G7-G12) generator

DFIG (G7-G12): ,UkWPrG 660= VrG 690= , AI rG 560=

transformer unit (T7-T12): ,kVASrT 700= kVrT 69.0 20 %)5(±=t , %5=krTu ,u %2.1=kRrT

line L2 overhead line (20kV): kmRL / 215.0 Ω= , kmX L / 334.0 Ω= , kml 102 =underground cable: kmRL / 162.0 Ω= , kmX L / 115.0 Ω= , l km 5.02 =

Wind farm 3 6 x 850 kW (G13-G18) generator asynchronous (G13-G18): kWPrG 850= ,U VrG 690= , I ArG 710= , kAI LR 5.5=transformer unit (T13-T18): ,kVASrT 1000= kVtrT 69.0 20 %)5(±= , %6=krTu ,u %1.1=kRrT

reactor MVASrR 5= ,U ,kVrR 20= %14=kru , %0=kRru line L3 overhead line (20kV): kmRL / 215.0 Ω= , kmX L / 334.0 Ω= , kml 103 =

underground cable: kmRL / 162.0 Ω= , kmX L / 115.0 Ω= , l km 13 = SHEP 3 x 1500 kW (G19-G21) generator

synchronous (G19-G21): S kVArG 1650= ,U VrG 690= , .. 18.0 upxd =′′ , cos )(9.0 lagrG =ϕ (operating p.f.=0.95 lag. to 0.95 lead., p.f. for KG and KSO =0.95 lead)

transformer T19: ,MVAS rT 5.3= kVrT 69.0 20 %)5(±t = , %8=krTu , %1=kRrTu T20: ,MVASrT 2= kVrT 69.0 20 %)5(±=t , %6=krTu , %1=kRrTu

line L4 overhead line (20kV): kmRL / 215.0 Ω= , kmX L / 334.0 Ω= , kml 5.74 =

TABLE 2 - FAULT LEVEL CALCULATIONS Network feeder )Ω( 161.0016.0Ω 25.8 2 jtZZZ rQQtQ +==⇒=

Network transformer )Ω( 682.1026.0

930556.0 ,Ω 808.1 Ω, 028.0,Ω 81.1jZ

KXRZ

T

TTTT

+=⇒====

Contribution of the upstream grid: MVA) 65.238S( 889.6)3.( k =′′=′′⇒ kAIkeq Wind farm 1 (synchronous with converter) generator k 299.15.1)13.( AIIeq rGki ==′′⇒

Contribution of WF 1: MVA) 4.5S( 156.0)/(6)13.( k =′′=′′⋅=′′⇒ kAtII rkikeq Wind farm 2 (DFIG) generator )Ω( 338.74434.7Ω 089.0 2 jtZZZ rGGtG +=⋅=⇒=

transformer )Ω( 164.28963.6015428.1 ,Ω 736.27 Ω, 86.6 ,Ω 57.28 jZKXRZ TTTTT +=⇒====

line L2 )( 398.3231.22 Ω+=⇒⋅+⋅= ∑∑ jZlXlRZ Li

iii

iiL

Contribution of WF 2: MVA) 95.20S( 605.0)6/6/(3

)7.( k2

max =′′=′′⇒++

=″⇒ kAIZZZ

UcI k

LTGt

nkeq

Wind farm 3 (asynchronous) generator )Ω( 552.60055.6Ω 072.0 2 jtZZZ rGGtG +=⋅=⇒=

transformer )Ω( 812.23441.4009282.1 ,Ω 593.23 Ω, 4.4 ,Ω 24 jZKXRZ TTTTT +=⇒====

reactor Ω 2.11== RR XZ

line L3 )( 455.3312.23 Ω+= jZ L

Contribution of WF 3: MVA) 17.15kS( 438.0)6/6/(3

)7.(3

max =′′=″⇒+++

=″⇒ kAIZZZZ

UcI k

LRTGt

nkeq

SHEP (synchronous) generator )Ω( 052.0008.0 008.0)( 2 +=⇒Ω=⋅′′⋅′′= GrGrGddGG ZSUxXRR

transformer )Ω( 832.112),Ω( 071.9143.1 )(20)(19 jZjZ HVTHVT +=+=

corr. factors 041465.1041465.1 , 997496.0 ,19 === SOGT KKK

(G19//G20+T19=Z1) (G21+T20=Z2)

)( 77.315.42 1919

21 Ω+=+⋅= jZKt

ZKZ TTr

GG , )( 77.579.8)( 202

2 Ω+=+⋅= jZtZKZ TrGSO

line L4 )( 505.2613.14 Ω+= jZ L

Contribution of SHEP: MVA) 75.18S( 541.0)//(3

)10.( k421

max =′′=′′⇒+

=″⇒ kAIZZZ

UcIeq k

L

nk

5. CONCLUSIONS In this paper, IEC Standard 60909 is applied for the calculation of the fault level in distribution networks with distributed generation resources. A practical approach is adopted for the short-circuit current contribution of the DG stations, which are not dealt with in IEC 60909, nor in any other relevant standard. The following main conclusions can be drawn from the paper: o From a fault level perspective, distribution networks are not designed to accept large

amounts of DG, because their short circuit capacity is already close to the design maximum value.

o Increasing the short-circuit impedance of the HV/MV transformer of the network is a realistic remedy to this problem. At the level of the DG station, reactors and other short-

circuit limiting devices can also reduce the DG contribution. More effective results, however, are obtained using advanced interfacing technologies.

o The need for a more active fault level management to permit increased DG penetration levels brings forward the importance of reliable, transparent and accurate fault level calculations.

6. REFERENCES [1] IEC 60909-0 (2001): Calculation of short-circuit currents. [2] IEC 60909-1 (2002): Factors for the calculation of short-circuit currents according to IEC

60909-0. [3] IEC 60909-2 (2002): Electrical equipment – Data for short-circuit currents calculation in

accordance with IEC 909 (1988). [4] IEC 60909-4 (2002): Examples for the calculation of short-circuit currents. [5] Gunter G. Seip “Electrical installations handbook” Verlag Publicis MCD 2000, John

Wiley & Sons. [6] Ismail Kasikci, Short Circuits in Power Systems: “A Practical Guide to IEC 60909”, John

Wiley & Sons, 2002. [7] B. De Metz-Noblat, F. Dumas, G. Thomasset “Calculation of short-circuit currents”

Schneider Electric, Cahier Technique no. 158, 2002. Summary: Fault level contribution is an important consideration for the interconnection of distributed generation (DG) to the distribution networks. In this paper, the latest edition of IEC 60909 International Standard is applied for the calculation of the resulting fault level in medium and low voltage distribution networks where distributed generation is connected. Calculation formulae are provided, including the various correction factors recommended by the Standard for the system voltage and the transformer and generator impedances. For the short-circuit current contribution of the DG units, reasonable assumptions are made based on the characteristics and the experience form the operation of such units. The methodology is applied to a study case MV network, which includes conventional –synchronous and induction– generators, as well as DG sources interfaced to the grid via power electronic converters.