with Non-Utility Induction Generators

2007 IEEE Canada Electrical Power Conference

Control and Protection of Distribution Network with Non-Utility Induction Generators Hamidreza Bakhshi*l, Innocent Kamwa*2

*]SNC-Lavalin T&D Inc., 25th Floor, 41J-Jst Street S.E., Calgary, AB, Canada, T2G 4Y5 [email protected]

*2Hydro-Quebec (IREQ),

1800, Lionel-Boulet, Varennes, QC, Canada, J3X IS] [email protected]

Abstract-In this paper, some topics related to the dynamic simulation and operations of Non-Utility Induction Generation (NUIG) are investigated. Various technical aspects related to the

cofnadistributi onswere anetw

mainUI

network conditions were analyzed d mainly by computer simulation of a distribution network and NUIG units uni connected concted simulation

to it. The applied simulation tool was EMTP-RV, which is a commercial electromagnetic transient simulation program. This paper presents the guidelines to limit the self-excitation phenomenon of NUIGs in islanding conditions and proposes proper protection schemes for interconnection of NUIGs to the distribution networks.

Keywords-Induction

generator;

dynamic

simulation;

self-excitation; islanding; relaying; NUIG; NUG; EMTP-RV.

1. INTRODUCTION rJ1He phenomenon of self-excitation of induction generators lhas been known for many years. It occurs when an isolated induction generator is connected to a system having capacitance equal to or greater than its magnetizing reactance requirements. Unintentional islanding of NUIGs may result in power-quality issues, interference to grid-protection devices, equipment damage, and even personnel safety hazards. Protective relay systems must be responsive to this condition and remove the NUIGs themselves from the island. Depending on the value of the capacitance and machine loading, terminal voltages of 1.5 to 2 per unit can be produced. This paper attempts to: 1- Examine the self-excitation and resulting overvoltages on the real 25 kV distribution network of Hydro-Quebec. This network contains the NUIG power plant which could face a fault and/or an unwanted network disconnection from the utility system. As a result, the problems likely to occur on the network have been analyzed, and subsequently recommendations in order to limit the self-excitation phenomenon have been presented. 2- Propose protection schemes and proper relaying criteria for interconnection of NUIGs to the distribution networks. The same local network system was used in [7, 8]. In [7] the focus was to examine the self-excitation phenomenon in the islanding condition using the Hydro-Quebec ST600

1-4244-1445-8/07/$25.00 ©)2007 IEEE

transient stability program. In [8] the focus was to examine the induction generator's parameters influence using the PSCAD-EMTDC power systems electromagnetic transients program. In the present work, the ElectroMagnetic Transient Program - Restructured Version (EMTP-RV) software is used tor-xmnthsefxcainpeoeonnteilndg to re-examine the self-excitation phenomenon in the islanding condition with the same terminology as [7]. Based on the results, practical guidelines have been derived to limit this phenomenon. It also proposes proper relay schemes for interconnection of NUIGs to the distribution networks.

2. SYSTEM DESCRIPTION AND MODELING ASPECTS Figure 1 shows the single line diagram of the studied 25 kV system as topology 1 (TOP 1) with the same system parameters as described in [7]. Modified system (TOP2) has been derived from TOPI with the connection of bus 2513 to bus 251 instead of a connection to bus 257. The objective of the modified network is to simulate a short-circuit case far away from the NUIG units.

Since islanding is either caused by feeder faults (which in turn can cause tripping of the feeder relay) or by an accidental tripping of the feeder relay, three scenarios have been considered for simulation conditions: i. Three-phase short-circuit at bus 259 (TOP1) at time t= 1 s, followed at t= 1.1 s by opening of the line between busses 251 and 250; and removing the short circuit at

t=2s; ii. Three-phase short circuit at bus 2511 (TOP2) at time t= 1 s, followed at t= 1.1 s by opening of the line between busses 251 and 250; and removing the short circuit at t=2s; iii. Simple islanding of the studied network by opening of the line between busses 251 and 250 at time t=1.1 s.

4. STUDIED CASES AND INITIAL POWER FLOW As described in section 3, all scenarios imply the opening ofthe line between busses 251 and 250. Therefore, the status

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2007 IEEE Canada Electrical Power Conference

2

of the sub-network located "below" this line on Figure 1 (TOPI) is of primary importance. Forty-five cases have been obtained by varying the load and compensation levels and their positions in the sub-network, as well as by

TABLE 1: INITIAL POWERFLOW

co

Base

Ref| PowerFlow

Induction Generator

Sub-Network

L.oad

Case Comp. ProdJuction Comp.

changing the load modeling.

251 to 250

m

Pf

Qf

MVAR MW MVAR MVAR MW MVAR MW MVAR

Hydra-Quebec 315 kV source

HQ

Bus 3151

"J)315-25kV 315: 25 kV

(Loss ofLine)

l31.2 km

0.295 MW 0.097 MVAR

5.35 km

0.126 MW 0.041 MVAR t

1.0 km

0.312 MW

6.56 km L

0.628 MW

0.206

MVAW

.9

4.0 km

25: 4.1 6kV . .[> Bus 51 0.6 M1VAR Tr 2.80 MW -1.51 MVAR

0.917 MW

) |

320

0.301 MVAR Fault Locatiorl

-

Short-circuit)

faIls falls GoryGory 0.701

MW

|

2

0.286 MW 0.094 MVAR

-1.13

2.63

5.31

1.74

0.66

3.32

-1.13

2.7

3.24

1.65

0.74

3.36

-1.06

3.01

3.24

1.49

s2 sl s2

1.14 1.38 1.6

3.38

-0.65 -0.4 -0.2

2.65 1.92 2.45

3.24 5.31 3.24

1.74 1.5

1-2.02 0

-0.21 0.74

-

0.65 0.66 0.67

3.26 3.28 3.32

-1.11

1.33

2.66

0.87

0.56

-0.74

-1.11

1.34

1.63

0.54

1.58

1.61

0.02

3.331 3.44

1.49

0 0 0

-0.3 0

0.44 0.25

3.26

0 -0.88

0 0

0.53 0.53

0.17 0.17

2.78 2.65

-0.31 -1.2

s12 s13

slO slO

0.445 2.225

3.2 3.47

-1.29 0.47

0 0

0.53 0.53

0.17 0.17

2.59 2.84

-1.63 0.14

s14

s15

slO s7

0.3223 2.09

3.18

3.38

0.32

-1.4

0 0

0.53 2.66

0.17

2.57

Bus 254

s16

s7

2.09

3.36

0.01

-0.83

3.32 3.24

3.22 5.31

1.06 1.74

0.06

-1.12

Bus 255

1.78 1.78

0 0 0

1.06

s7

0.3 0 0

3.22

s17 s18

1.78

3.26

0

2.63

10.6

3.49

3.38 3.39 3.17 3.21

0.28 0

1.32 2

-1.51 -1.1

0.665

5.31 5.31 0.53 3.19

1.74 1.74 0.17

s7

2.05 1.78 0.2 0.65

s24 s25

slO s7

0.5933 0.65

3.22 3.26

-1.16

-1.11

0 1.33

0.53 3.22

s26

slO

1.78

3.4

slO slO

1.78 1.78

3.4 3.4

0 0 0

0 0 0

s29 s30

slO slO

0.41 0.3223

3.18

3.19

-1.32 -1.4

s31

slO

0.44

3.2

slO

0.41

3.19

slO

slO

1.78

1.78

3.34

535 sl s36 slO

1.78

S37

MVAR

s19

9M\A

41kBus 258

Bus2510

The result of performing simulations of the 45 cases for 100 ms is shown in Table 1. This table gives the initial power flow of all studied cases and is organized as described in [7]. However, no numerical divergence is observed with EMTP-RV in contrast to [7]. 5. RESULTS ANALYSIS In the analysis of the results, we will pay attention to the

behavior of the 25 kV network after the occurrence of typical perturbation with reference to the: (a) topology, (b) contingency, (c) system load level, (d) capacitive self-excitation level and position, (e) reactive compensation of the network, (f) load type, and (g) protection system. Observations taken at bus 51 where the NUIGs are connected include the voltage (p.u.), the frequency (Hz), the active power (MW) and reactive power (MVAR). Only the analysis ofthe voltage (p.u.) is presented in this paper.

s38 S39

-1.11

1.7

1.63

0.54

0.87

0.66

-0.4

-1.75

-0.63

-1.99 -1.77

-7.18

1.08 -0.2 0.21 -1.86

0.17 0.87

2.61

-1.49

0

0.53

0.17

0.53 0.53

0.17 0.17

2.78 2.78 2.78

-0.73 -0.32 -0.32 -0.33

0 0

0.53

0.17

2.58

-1.66

-1.3

0

0.53

0.17

2.59

-1.64

-1.32

0

0.53

0.17

2.58

-1.67

1.68

0

0.74

0

0.53

0.17

2.77

-0.19

1.78

3.48

0

2.63

4

1.31

-0.68

2.78

-0.32

sl

1.78

3.34

1.78 1.78

3.5 3.39

0

1.32

-0.73

sl sl

00

3.22 3.2

-

si slo

S33 S34

Fig. 1: Real studied system (TOPI)

sl

s21

s32

Bus 2511

-

sl

s27

k

s7

s20

s22 s23

Bus 257

Bus 259

~~~~3.5 km

-2.9

3.39

ls28

(Three-phase

10

-2.07 -2.07

1.78

L1. Aj 25: 25 kV \

9

1.74

0.89

krMw

3. k T

8

5.31

slo

Bus 256

~

7

0

slo sll

1.6 km

Bus 2513

s2

S9

~~~~~~Bus251

=-r1.

s3

6

s7

0.7 km

0.103 MVAR

s2

5 -1.11

0.64

4 3.08 3.27

s8

Bus 253

2.045 MW

-

s6 s7

Bus 252

0.672 MVAR

3 0.59

|s5

Bus 250

FauIt Locat 6l.8 MVAR

2 sl

s4

ry "n 21 MW

1 sO sl

s40 sl

3.4

1.78 3.35

0

0 0

0

0

0.53

0.53

0.87

0.17

0.17

0

0.53

0.17

0

5.31

1.74

2 1.51

5.31 4

-1.97 -2 2.55 o

2.57

1.11

-1.3.9

-1.76

0.57

1.3

1.74 1.31

1.4 1.3 -0.69 0.16

1.06

0.11

S43 s7

0.65

3.34 -1.14

2.63 4 1.31 -0.78 1.2 1.45 2.6 -0.62 -0.62 1.45 0.53 0.53 0.17 0.17 2.6 1.33 2.66 0.87 0.59 -0.83

S44

2.09

3.39

0.23

S7 S42 slO0

s41

s7

0 -1.7

-1.73

0.32

3.22

-0.57

5.1 THREE-PHASE SHORT CIRCUIT FOLLOWED BY ISLANDING Figure 2.a demonstrates the typical examples of the voltage behaviors in the case of a three-phase short-circuit fault close to the NUIG for five base cases (si, s2, s7, sO0 and s19). The results have shown that NUIG could not support the sub-network after three-phase fault inception at bus 259 (TOP 1). However, in some cases the capacitor is sufficient for the self-excitation phenomenon (e.g. s10). Figure 2.b shows voltage behaviors for two cases (s33 and s40) considered as modified systems to simulate a three-phase fault far away

196

2007 IEEE Canada Electrical Power Conference3

from the NUIG. The results have shown that in the case of a 5.2.3 INFLUENCE OF THE COMPENSATION AND LoAD LEVEL on the Figure 4.a shows the voltage behavior of two cases (s35, generator terminal is near the nominal rates and the fault and s39). Both cases have the load in sub-network higher than represents only an additional load to the generator. After the NUIGs generation (see Table 1). In the case of s35 the separation of the sub-network from the utility system in both sub-network is extremely over-compensated (Q-1..3 MVAR), conditions (at busses 251 and 2511), the voltage drops very whereas in case s39 the compensation is reduced. Figure 4.a fast (the voltage drops to 0.2 p.u. in 3 cycles) and NUIG is no shows that the occurrence of self-excitation phenomenon longer a source of load or fault curr ent. depends more on the active load level in the sub-network ______________ ___ ~~~~~~rather than the compensation level.

three-phase fault at bus 2511 (TOP2), the voltage

~~~~~5.2.4 INFLUENCE OF THE LoAD MODEL ~~~~~~Cases s2 1 and s3 8 correspond to the same initial operation 4~~~~~~~ OA- 0 and respectively 000 and 700o of their loads are L 12 __ ~~~~~~~~represented with constant power. Figure 4.b illustrates that as the percentage of constant power load increases, the rate at -OA~~ ~ ~~ Time(S) which the voltage collapses is quicker. oc
0

Time(s)

Fig. 2.a: At bus 259 (TOPI) Fig. 2.b: At bus 2511 (TOP2) Fig. 2: Short-circuit followed by network disconnection, voltage variations 5.2 ISLANDING CONDITION

9

Scenario iii of section 3 has been followed in this part. 5.2.1

INFLUENCE OF THE SYSTEm LoAD LEVEL Figure 3 .a shows the voltage behavior of five base cases >S (s 19, si1, s2, s7 and slO ). With respect to the base case s I, the 3 loads are divided by 1.64 in case s2, divided by 2 in case s7,/ divided by 10 in case slO , and multiplied by 2 in case s 19. In all five cases the reactive compensation is sufficient4

(negative Qf in Table 1). Figure 3.a clearly illustrates that

voltage

reducd, sel-excittion sel-excittion ad ad over is more likely to occur. when th th load evel when load evel

ii

over

5.2.2

INFLUENCE OF THE COMPENSATION LEVEL Figure 3 .b shows the voltage behavior of six cases (s22, s 14, s31, s ItI, s I 0 and si1 3). With respect to the base case s I 0, the cases s ItI, s3 1, s 14 and s22 correspond to a reduction in the value of the capacitor compared to case s 10, and case s 1 3 corresponds to an increase in the value of the capacitor (see Table 1). Figure 3.b illustrates that by increasing the compensation of machine, the rise of voltage is faster (the voltage reaches 2 p.u. in 0.35 s).

~ ~ 2

7re()nnp

Fig. 4.a: Influence of compensation level Fig. 4.b: Influence of load type Fig. 4: Simple disconnection of Hydro-Qu6bec's source, voltage variations 5.3 PLAN OF POWER RATios

The simulation results have shown that two important factors in the occurrence of self-excitation are: a) the active load level (compared to the induction machine active power output), which determines the frequency variation after disconnection, and, b) the reactive compensation level (compared to the system reactive consumption), which determines the voltage variation after disconnection. Thus, the following two power ratios have been considered: PR; is the ratio between the initial active power consumed in the sub-network and the initial active power produced by the generator. PPgPj Pf: Active power flowed from busses 251-250 R

S13

p

~~Pg

Active power produced by generators

9~~~~~~~~~~

QR; is the ratio between the initial reactive power ~ ~ ~~cnumed in the sub-network (including the machine 777:,V~~~~~~~~~ consumption) and te initial reactive power produced bytte three capacitors at busses 51, 255 and 257. Lw

2007 IEEE Canada Electrical Power Conference

4

TABLE 2: COMPARATIVE TIMES AND DIAGNOSTICS

which have been used to derive practical guidelines presented below in section 6. These results are also consistent with those obtained in [7]. 3.5

tv120

tv140

tf63

(ms)

tf61.5

No.

(ms)

(ms)

(ms)

0

-

-

151.76 331.63

191.99 379.14

1

PR

lil

2

N o self excitation

3

1

23~~~~ ---------0

T-IE A---8

COPAAT. 1.5

0onsidering QRdro-Quebec srequirements[13]re 2

3

4

5

6

7

8

9 10 11

g12

TiMES

1111 153.17

312.43

~~~~~~

238.64 9 .32 ~~~~~~~

13 15

for 45 cases

T

7

14

Fig. 5: Simple disconnection of Hydro-Qubhec's source, plan of power ratios

Results showA

1~

10 161

0.5.-------NS1

1 ~

~~

-

0

0

3

Self-excitation

2.5-

16 17 18

after PROTECTION SYSTEM the

CONSIDERATIONS

19

Considering Hydro-Quebec's requirements [13] regarding the frequency and voltage thresholds and using the simulation

20 21

22 23 24 25

results of 45 cases, times to reach the assumed different thresholds for the frequency (61.5 Hz and 63 Hs) and for the voltage (1.2 p.u. and 1.4 p.u.) in the islanding condition were calculated and presented in Table 2.

26

Results show thatafter separation of the sub-network: 3-RThesultsuencythataftereseparationoldthesub-network:27

1- In all cases the frequency, and in most cases the voltage, passes different thresholds very fast and reaches to the frequency in which, as per Hydro-Que'bec's requirements, the protection systems must trip instantaneously and disconnect the sub-network from the NUIG; 2- The times needed to reach the different thresholds are often very short, and their comparison shows that tf63 iS smaller than tV14 and tV2 in most cases and te61.5 is always

3- The frequency threshold of 61.5 iz permits the detection of all cases except 6 (s2, s3, 4, s6, s35, s40), but the voltage thresholds solely are not reliable to detect the islanding co. ...........

4- Case s2, where the initial powers are altost balanced (see Table 1), is a special case because it presents very small voltage and frequency deviations in the prohibited tripping

6

195.4 131.23

0 0

92.03 ~~~~~~~~962.92

0

62.92 15.2

143.73 82.06 91.75 236

65.56 63.49

94.7 92.82

193.98

569.98

843.46

940.91

1084.3

45.38

94.44

664

-

-

-

-

-

-

-

-

-

-

-

-

-

1384.2

1580

-

-

340.27

559.28

-

-

63.39

130.12

63.16

129.71

68.93

704.33

31 32 33

136.16 909.21 1100 862.38 922.81 138.57

88.32

215.15

-

-

35 36 37

69.39

136.81

-

-

~~~

~

40

-

-

41 42

77.87

151.79

-

-

~

*

126.71 87.4

-

136.29 329.13

959.21 593.82 716.41 70.6

34

346.74 395.04 ~~~~ -357

~

68.61

28 29

30

smaller than tv12;

zone;

Case

65.82

125.01

0 94.82

0 0 0 0

153.12

197.97

233.68

0 0

136.38 191.88

198.37 236.72

** *

351.88 393.18 65.55

442.58

62.91 168.41

92.04 255.62 91.28

0 0 0

62.61

90.97

0

246.19

127.95 62.61

274.49 400.7

94.84

*

181.82

63.15

91.81 0

94.53

0

65.99 65.66 65.99 63.54

95.49 94.83 95.66 92.83

0 0 0

65.55

111.27

174.51

-

-

63.58 189.27

1

92.41

O

0

0

225.94s*

278.46 314.95 ~~~~~~~~~~~~~~~38 -

527ICA 638AYS -

*

64.4 129.56

95.18 202.14

0 0

908.4 120.27 dependitions;g43 ...... o widely o 4N sl-ea oS

183.19

0

D6.7 D

TYPICAL RELAYS IN INTERCONNECTION PROTECTION SYSTEMS

5- For the other 5 cases, in which the voltage and the The functional levels of interconnection protection vary frequency both drop, they could easily be detected with a widely depending on factors such as: generator size, point of threshold of 57 liz, for instance.. interconnection to the utility system (distribution or The simulation results show that for the island'ng su-rnmsi),tpofnecnetonothuily,ye condition, if it were caused by a feeder fault (conclusion from section 5. 1), over/undervoltage relays could be used and if it is of ertor (inuction, s caused simply by an inadvertent trip of the substation breaker Tanoer couration. Table 3 icludes a non-exhaustive list of typical protection (conclusion from section 5.2 and 5.4), then over/uderfreuency elays ould b requied. Threfore relays, which may be used in the interconnection protection minimum protection requires over/undervoltage relays an systems of different types of Non-Utility Generations (NUGs). over/uderferuencyelays n all UIGs.The specific objectives of an interconnection protection system, as well as the relay functional requirements with respect to each objective are shown in Table 3 [10, 14].

s(induction) synchrconnectiontoitheutilnection gns

198

2007 IEEE Canada Electrical Power Conference

5

TABLE 3: TYPICAL INTERCONNECTION RELAYS FOR DIFFERENT TYPE OF NUG

Interconnection Protection Objective

IEEE No.

Fault Backfeed Detection

Application

50

instantaneous overcurrent

51

overcurrent with time delay

5ON

neutral instantaneous overcurrent

|51N

neutral overcurrent with time delay

51V _______

voltage-restrained overcurrent

67

directional overcurrent

67N

neutral directional overcurrent

21

distance

59N

neutral overvoltage

27N

neutral undervoltage

SUSCEPTIBLE TO THE SELF-EXCITATION GH Wye-Wye CONNECTED THIROUI

TRANSFORMER

CT

instantaneous

1

2 or 3VTs

59

27

591 ou Note 1

over and underfrequency

591 59

instantaneous overvoltage

TT

transfer trip

Detection of Damaging System

Conditions

47 46

negative sequence voltage negative sequence current

Abnormal Power Flow Detection

32

directional power

Restoration or Synchronization

25

synchronization

~~~~~~~~~~~~~~~~~~~~~~~~~~~~~51Vl

ZCTs

undervoltage

Note 2

overvoltage

A

1

Notes,

1- Required only if is possible.

B

(1), 25

Note 3

E

~ ~ ~ ~ ~ ~ ~ fer oresonance

271

1j

C

\

27

2- Required only if time is to slow operating forfeed faults.

l

Figures 6 and 7 show single line diagrams of typical interconnection protection relays for NUIGs respectively susceptible and not susceptible to the self-excitation and connected through Wye-Wye transformers [2, 10, 14]. Relay numbers and their functions in Figures 6 and 7 are explained in Table 3. 7

1N

yrT

81 O/U

Detection of Loss of Parallel Operation with Utility System or Detection of Islanding Conditions

NUIG RELAYING FOR INDUCTION GENERATORS

undervoltage _______

27 271

,

\V\Jisilble LockabDle Switch 0

3- Use one or other

only if feeder unbalance can transformer over loading.

cause

Fig. 6: Single line diagram of NUtIG relaying, susceptible to the self-excitation and connected through Wye-Wye transformer

INTEGRATION CRITERIA AND RECOMMENDED PROTECTION SYSTEM

The following practical guidelines could be derived for the integration of NUIGs to the Hydro-Quebec's distribution network based on the simulation results presented in section 5 and previous research presented in section 6: 1- Compute the ratio between the initial value of the

minimum active load that could remain connected to the generator after separation and, the nominal active power of the generator (PR); 2- If the ratio (PR) is smaller than 3, self-excitation phenomenon could occur. Hence, the total capacitive compensation should be between 10% and 50% of the machine reactive compensation; then the full complement of relays shown in Figure 6 with a minimum time delay should be used. 3- If the ratio (PR) is higher than 3, the probability of having self-excitation is very low. So, the total amount of capacitive compensation is not critical, but it should not exceed the machine reactive consumption; then the reduced complement of relays, shown in Figure 7 with usual settings can be used.

4- In cases when the compensation cannot be reduced due to

~

operation neesiis

TrnfrTi.

T)o h

eeao

could possibly be considered.

199

NUIG RELAYING FOR INDUCTION GENERATORS C EPTI TTHE SELF-E TRANSFORMER

1 CT

51N

,

A

47 f

271 B

c L

1 Required only if

ferroresonance is possible.

0 Fig. 7: Single line diagram of NUIG relaying, not susceptible to the self-excitation and connected through Wye-Wye transformer

5

2007 IEEE Canada Electrical Power Conference

6 K. Kauhaniemi, L. Kumpulainen, "Impact of distributed generation on the protection of distribution networks" Developments in Power System Protection, IEE International Conference, 5-8 April 2004, Amsterdam,

[6]

8 CONCLUSION This study was made of two parts. The first part focused mainly on the self-excitation phenomenon which resulting overvoltages on an actual 25 kV distribution system. As a result, practical guidelines to limit the occurrence of this phenomenon have been derived from this phase of the case study. In the second part, the Impact of NUIGs on the

pp. 315-318. [7] R. Belhomme, M. Plamondon, H. Nakra, D. Desrosiers and C. Gagnon, "Case study on the integration of a non-utility induction generator to the

Hydro-Quebec's

Distribution network" IEEE Transaction on Power

delivery, Vol. 10, No. 3, July 1995. [8] R. Wamkeue, S. Moraogue and I. Kamwa, "Distribution network fed in co-generation by induction generators: Incidence of self-excitation phenomenon" IEEE International Conference on Electrical Machines

performance and coordination of feeder's protective devices during fault events was studied. Simulation results showed

and Drives, ICEM 2001, 2001, pp. 594-603. [9] R. M. Rifaat, "Critical considerations for utility/cogeneration inter-tie

after an islanding condition, it is no longer a source of load or fault current. This also proved that after an islanding

[10] Charles J. Mozina, "Interconnection protection of IPP generators at

protection scheme configuration", IEEE Transactions on Industry

that NUIGs contribute only 2 or 3 cycles of fault current, but quality is not guarantied and anticondition, the condition, the power quality Is not guarantied and antipower

islanding protection for NUIGs is a more challenging problem in comparison with the other type of faults. Based on practical guidelines presented in section 7, the NUIG owner must demonstrate that: > The NUIG protection systems are capable of detecting a power island condition. > In the event of self-excitation, isolation of the NUIG will occur quickly enough to preclude damage to other customers or utility system from the abnormal voltages that may occur.

Applications, Vol. 31, No. 5, September/October 1995, pp. 973 - 977.

commercial/industrial facilities", IEEE Transactions on Industry Applications, Vol. 37, No. 3, May-June 2001, pp. 681-688. [1 1] IEEE Standard 1547-2003, "Standard for interconnecting distributed

resources with electric power systems". [12] IEEE Standard C37.95-1989, "Guide for protective relaying of utility-

consumer interconnections". [13] Hydro-Qu6bec's Standard E.12-01-2005, "Requirements relating to the

connection of decentralized production to the distribution networks of

Hydro-Quebec".

[14] IEEE CharlesTransactions J. Mozina, on "Interconnection protectionVol.of dispersed generators", 5, 8-12 Oct., 2000, pp. Industry Applications,

3273-3280. [15] G. Bizjak, D. Zvikart, "Behaviour of small hydroelectric power plant generators during the fault in distribution network (digital simulation study)", IEEE Transmission and Distribution Conference and Exposition, 2001 IEEE/PES, Vol. 1, 28 Oct.-2 Nov. 2001, pp. 481-485.

> The interrupting device used to separate the NUIG generator from utility system is capable of operating at the elevated voltages which may occur following

11 BIOGRAPHIES

self-excitation. Unless the NUIG owner can demonstrate through the

Hamidreza Bakhshi received his B.Sc. from Iran

University of Science and Technology, Tehran, Iran, in 1993 and his M.Sc. from Laval University, QC, execution of analytical studies, that there is no risk of in 2006, both in electrical engineering. self-excitationof generator. the self-excitationofthe generator. is a registered professional engineer with ~~~~~~He In assessing the opportunity for the self-excitation over 10 years experience in the field of overhead power transmission lines in Iran and Canada. Since phenomenon, the presence of existing generators on the same he has been with SNC-Lavalin T&D in the feederwith alongwith miimum load likely lkely to be connected onnectedttoTransmission feeder along the the minimum o2006, Line Division.

~~~~~~~~~Canada,

the feeder must be taken into consideration. 9

ACKNOWLEDGMENT

Innocent Kamwa (S'83-M'88-SM'98-F'05) received The authors gratefully acknowledge the contribution of his Ph.D. degree in electrical engineering from Laval B. Khodabakhchian Hydro-Qu~bec, whose valuable B. Khodabakhchian from Hydro-Que'bec, valuableUniversity, QC, Canada, in 1988. Since then, he has been with the Hydro-Quebec Institute/IREQ, Power comments helped to improve this paper. System Analysis, Operation and Control, Varennes,

10

QC, where he is currently a Principal Researcher in

REFERENCES

[1] A. Borghetti, R. Caldon, S. Guerrieri and F. Rossetto, "Dispersed generators interfaced with distribution system: dynamic response to faults and perturbations" Bologna PowerTech Conference, Bologna, Italy, 2003 IEEE, June 23-26. [2] D. Dawson and W. E. Dugan, "Interconnecting distributed generation to utility distribution system", Short Course, University of WisconsinMadison, June 1999. [3] In-Su Bae, Jin-O Kim, Jae-Chul Kim and C. Singh, "Optimal operating strategy for distributed generation considering hourly reliability worth", IEEE Transactions on Power System, Vol. 19, No. 1, February 2004. [4] M. Begovic, A. Pregelij, A. Rohatgi and D. Novosel, "Impact of renewable distributed generation on power systems" System Science, Proceedings of the 34th Annual Hawaii International Conference on, Jan. 3-6, 2001, pp. 654-663, Maui, Hawaii. [5] T. Ackermann and V. Knyazkin, "Interaction between distributed generation and the distribution network: operation aspect" IEEE/PES Transmission and Distribution Conf. and Exhibition 2002: Asia Pacific, Vol. 2, 6-10 Oct. 2002, pp. 1357-1362, Yokohama, Japan.

bulk system dynamic performance. He has been an Associate Professor of Electrical Engineering at Laval University since 1990. Dr. Kamwa has been active for the last 13 years on the IEEE Electric Machinery committee where as a Working Group Chair and Secretary, he contributed to the latest standards 115 and 1110. A member of CIGRE and a registered professional engineer, Dr. Kamwa is a recipient of the 1998 and 2003 IEEE Power Engineering Society Prize Paper Awards and is currently serving on the Adcom of the IEEE System Dynamic Performance Committee.

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