Investigation-7-8-9(1)

N e w Z e a l a n d E l e c t r i c i t y C o m m i s s i o n - W i n d G e n e r a t i o n I n v e s t i g a t i o n P r o j e c t

Stage 1 - Wind Generation Impact Studies

Final Report

prepared for

Transpower NZ LTD

N e w Z e a l a n d E l e c t r i c i t y C o m m i s s i o n - W i n d G e n e r a t i o n I n v e s t i g a t i o n P r o j e c t - S t a g e 1 2

DIgSILENT GmbH Heinrich-Hertz-Strasse 9 D-72810 Gomaringen Tel.: +49 7072 9168 - 0 Fax: +49 7072 9168- 88 http://www.digsilent.de e-mail: [email protected]

Please contact

Koos Theron Tel.: +64 3 9690 0081 e-mail: [email protected]

Team

Brad Henderson B.E Dr.-Ing. Markus Poller

Published by DIgSILENT GmbH, Germany

Copyright 2003. All rights reserved. Unauthorised copying or publishing of this or any part of this document is prohibited.

May, 2007

T a b l e o f C o n t e n t s


Table of Contents

1 Executive Summary........................................................................................................................... 5 1.1 Background .............................................................................................................................................. 5 1.2 Study Objectives....................................................................................................................................... 6 1.3 Study Results ........................................................................................................................................... 7

1.3.1 Voltage Sag Screening Results North Island........................................................................................ 7 1.3.2 Voltage Sag Screening Results South Island ....................................................................................... 7 1.3.3 Dynamic Simulation Results North Island............................................................................................ 7 1.3.4 Dynamic Simulation Results South Island ........................................................................................... 8

1.4 Conclusions and Recommendations............................................................................................................ 8 1.5 Study Assumptions ................................................................................................................................. 10

1.5.1 Scenarios .......................................................................................................................................... 10 1.5.2 Wind-farms ....................................................................................................................................... 11

1.6 Voltage Sag Screening ............................................................................................................................ 12 1.6.1 Voltage Sag Study Methodology.......................................................................................................... 12 1.6.2 North Island Power System Key Results............................................................................................ 13 1.6.3 South Island Power System Key Results ........................................................................................... 16 1.6.4 System Impact from Medium Voltage Faults (110 kV) .......................................................................... 18

1.7 Options to reduce wind farm tripping ....................................................................................................... 19

2 Dynamic Wind Impact Studies ........................................................................................................ 21 2.1 Study Assumptions ................................................................................................................................. 21

2.1.1 Wind-farms ....................................................................................................................................... 22 2.2 Dynamic Simulation of the NZ System...................................................................................................... 23

2.2.1 Dynamic Study Methodology............................................................................................................... 23 2.3 Summary of Dynamic results for the North Island ..................................................................................... 24

2.3.1 Wind Generation Tripping................................................................................................................... 24 2.3.2 Electrical frequency at Huntly ............................................................................................................. 25 2.3.3 Short term voltage instability, North Island.......................................................................................... 27 2.3.4 Interconnecting line flows, North Island .............................................................................................. 30

2.4 Summary of dynamic results for the South Island ..................................................................................... 30 2.4.1 Sudden Loss of Wind Generation ........................................................................................................ 30 2.4.2 Electrical frequency at Clyde............................................................................................................... 31 2.4.3 Short term voltage instability, South Island ......................................................................................... 33 2.4.4 Interconnecting line flows South Island ............................................................................................... 35

3 Concluding Remarks and Recommendations.................................................................................. 36

T a b l e o f C o n t e n t s


4 References....................................................................................................................................... 37

1 E x e c u t i v e S u m m a r y


1 Executive Summary

1.1 Background Transpower has engaged DIgSILENT to investigate the effects of the connection of large scale wind generation to the NZ power system. This study is part of the Electricity Commission's Wind Generation Investigation Project (WGIP).

The impact of large amounts of new wind generation on the stability of any power system can be significant, especially if the wind generation is not equipped with Fault Ride Through (FRT1) capability. If wind generators without FRT capability are widely used, a fault on the power system may cause voltage sags that can cause large amounts of wind generation to disconnect from the power system. The consequences include fast frequency drops, load shedding and voltage stability problems.

To investigate the impact of the of large scale wind generation on the New Zealand power system, ten independent scenarios have been created for each of the North and the South Island systems. The scenarios consist of five different wind generation levels (from 0-100% of installed wind generation capacity) and two forecast load scenarios (high and low load) for the year 2016.

According to Electricity Commissions Scenario C, the peak installed wind generation capacity for the North Island will be 1600 MW, while the system is forecast to have a peak demand of 5460 MW in 2016. In this extreme situation with 1600 MW of wind generation and 960 MW supplied from the HVDC inter island link, only 50% of the load will be supplied by other generation during some hours2. For light load conditions where forecast load will be 2130 MW, only 25% of the load will be supplied by other generation.

The South Island power system is forecast to have a peak load of 2520 MW in 2016. With the assumptions of the Electricitys Commissions Scenario C, which is a peak installed wind generation capacity of 700 MW, only 75% of the load will be supplied by other generation. In light load conditions, this could drop to as low as 40%.

With such high levels of wind generation relative to other generation, a considerable impact of wind generation on power system stability must be expected, especially if it is assumed that wind generation technology is without FRT capability.

1 This study discusses FRT by the simulation of voltage dips. The term LVRT (Low Voltage Ride Through) essentially refers to the same aspect but also includes post-fault wind generator behaviour, e.g. in the case of slow voltage recovery. However, in literature, both terms are often used to describe the same behaviour.

2 In reality, max. 90% to 95% of installed wind generation capacity will be available simultaneously. Hence, assuming 100% availability is a conservative study assumption.



1.2 Study Objectives The Wind Generation Investigation Project (WGIP) is expected to involve several stages of analysis. For the stage one study, the impact of wind generation on system stability is analyzed. In this stage of the study all wind generators are without FRT capability.

For this stage of the study a two step approach has been taken:

Stage 1.1 of the study will establish the likely amount of wind generation that would trip off in each island in each of the ten scenarios for faults at high voltage bus bars. The focus is on 220kV bus bars because it can be expected that faults at the highest voltage level affect the largest areas. However, also faults at some 110kV bus bars are studies for verifying this assumption. The studies will be performed using steady-state (short circuit) analysis.

The key objectives for stage 1.1 are:

Assessment of the amount of tripped wind generation for a fault at each HV bus in the system under worst case assumptions (no FRT-capability of any wind generator);

Identification of critical cases, by comparing the amount of lost generation with the normal spinning reserve in each island (largest conventional unit);

Recommendations for reducing the amount of tripped wind generation;

It is important to emphasise that:

Wind generators in this study are fixed speed asynchronous machines without FRT capability and have no fast acting reactive power compensation devices;

This is a transmission system impact study. Localised issues are not assessed. Some local issues must be addressed in order to obtain sensible and consistent results, but these are not the focus of this study. It is anticipated that any localised issues will be assessed in later stages of the study;

The primary purpose of the stage 1.1 studies is to determine the most severe faults - the faults causing the greatest amount of tripped wind generation.

Stage 1.2 of this study will build on the results gained from stage 1.1 and perform dynamic analysis on the system for a selection of the most critical cases.

Stage 1.2 will look to identify the following key aspects:

Confirm the results of stage 1.1 studies with dynamic simulations;

Highlight the impact of tripped wind generation on frequency and voltage stability. In particular to identify any cases where the automatic under frequency load shedding (AUFLS) frequency limits are reached and observe any cases of inadequate voltage stability.



1.3 Study Results

1.3.1 Voltage Sag Screening Results North Island

High-wind scenario (Wind generation is 100% of installed wind generation capacity):

During high load for the majority of 220 kV system faults, more than 350 MW of wind generation will trip. This exceeds the normal spinning reserve of 350 MW.

During light load, many system faults cause the entire wind farm capacity of the North Island (1600 MW) to trip.

Low-wind scenario (Wind generation is 25% of installed wind generation capacity):

During high load, only one 220 kV system fault causes more than 350 MW of wind generation to trip. During light load, over 50% of the 220 kV faults cause more than 350 MW of wind generation to trip.

1.3.2 Voltage Sag Screening Results South Island High wind scenario (100% wind generation):

During high load for the majority of 220 kV system faults, more than 120 MW of wind generation will trip. This exceeds the normal spinning reserve of 120 MW.

During light load, many system faults cause the entire wind generation capacity of the South Island (700 MW) to trip.

Low wind scenario (25% wind generation):

During high load, the majority of 220 kV system faults cause less than 120 MW of wind generation to trip.

During light load, a majority of the 220 kV faults cause more than 120 MW of wind generation to trip.

1.3.3 Dynamic Simulation Results North Island The voltage sag screening identified 20 critical cases from the North Island for in-depth dynamic simulation. The results of these studies confirm the results obtained by the voltage sag screening and show the under frequency and voltage stability problems caused by excessive wind generation tripping.

The results of the dynamic analysis for the North Island can be summarized as follows:

For a majority of the 20 cases the predicted tripped wind generation from the static analysis agrees with the observed results from the dynamic simulations.

In 10 of the 20 cases the block 1 AUFLS set point of 47.8 Hz was reached. Short term voltage instability was observed in several of the light load cases where a large amount of

wind generation tripped for 4 of these cases it is unlikely that load shedding would act fast enough to prevent a complete system collapse.



1.3.4 Dynamic Simulation Results South Island The voltage sag screening identified 10 critical cases from the South Island for in-depth dynamic simulation. The results of these studies confirm the results obtained by the voltage sag screening and show the under frequency and voltage stability problems caused by excessive wind generation tripping.

The results of the dynamic analysis for the South Island can be summarized as follows:

With the exception of two of the 10 cases, the predicted tripped wind generation from the static analysis agrees exactly with the observed results from the dynamic simulations.

For 2 of the 10 cases the block 1 AUFLS set point of 47.5 Hz was reached. Short term voltage instability was observed in case S_026 and case S_028 where a large amount of wind

generation tripped. In case S_026 it is unlikely that load shedding would act fast enough to prevent a complete system collapse, whereas in case S_028 the load shedding would probably act fast enough to prevent the voltage instability.

1.4 Conclusions and Recommendations The results of the voltage sag screening have shown that many (n-1) contingent events, such as faults on single transmission circuits, can lead to widespread tripping of wind generation if wind generators are not equipped with FRT capability.

Observations from the dynamic simulations show that widespread tripping of wind generation can drive the system into frequency stability problems resulting in widespread load shedding, or into dynamic voltage stability problems.

For avoiding widespread load shedding following a contingent event during high wind generation there are mainly two options, increasing spinning reserve and system inertia or building all major wind farms with wind turbines having FRT capability.

However, increasing spinning reserve and system inertia requires that almost all wind generators are backed up by non-wind generators, which leads to enormous additional spinning reserve. Besides this, the network must be able to transport any additionally required reserve power. In this study, a number of cases were identified, where the available transport capacity is not sufficient and consequently, the network runs into dynamic voltage collapse. For avoiding this, network reinforcements would be required or inter-area power transfer must be limited.

The second option, only allowing wind generators with FRT-capability, is fairly easy to realize because this kind of wind generator is standard technology. Consequently, for avoiding drastically reduced reliability of supply in the New Zealand power system there is only one practical solution:

Only allowing the connection of wind generators with FRT-capability.

This has become an international standard for power transmission systems with high wind penetration, e.g. in Germany, Denmark, U.K. or Australia.



When connecting wind generators with FRT capability, additional reserve power is only required for backing up wind fluctuations but not for backing up wind generator trips.


N e w Z e a l a n d E l e c t r i c i t y C o m m i s s i o n - W i n d G e n e r a t i o n I n v e s t i g a t i o n P r o j e c t - S t a g e 1 1 0

Voltage Sag Screening

1.5 Study Assumptions For each island, 10 predefined load and wind generation scenarios were created. A brief summary of these scenarios is given below in Table 1-1 and 2-2. When wind generation increases from 0-100% of installed wind generation capacity less other generation is dispatched, resulting in a weaker system (lower grid short circuit level). For more detail on the methodology for the development of the generation scenarios and modelling of the wind generator plant please refer to the modelling report [1].

It is assumed that faults are cleared after 120ms, based on first zone protection tripping time and maximum breaker delays or transfer tripping delays.

1.5.1 Scenarios

Case Load (MW) Wind Generation (MW) HVDC Import MW

High Load 100% Wind Generation 5459.2 1603.6 960





Light Load 100% Wind Generation 2131.4 1603.6 0





Table 1-1 - Wind generation scenarios, North Island

Case Load (MW) Wind Generation (MW) HVDC Export MW











Table 1-2 - Wind generation scenarios, South Island



1.5.2 Wind-farms There are three existing wind-farms greater than 10MW on the New Zealand system, Te Apiti, Tararua and White Hill. In addition to these, nine new wind-farms are modelled to bring the total installed capacity for the North Island to approximately 1600 MW and the installed capacity for the South Island to approximately 700 MW. Each of the new wind farms is scaled from 0 to 100% of installed wind generation capacity to create five generation scenarios for each island3.

Each wind-farm was modelled with generic fixed speed asynchronous machines with no built in FRT capability and no fast acting reactive power compensation. Further, it was assumed that each generator had no contribution to the short circuit level of the grid.

The wind-farms are shown in the tables below.

Wind-farm PCC (bus) Units Total Capacity (MW)

Marsden MDN220 91 150

Otahuhu OTA220 182 300

Huntly HLY220 61 100

Hawkes Bay RDF220 182 300

Manawatu BPE220 182 300

Wilton WIL220 182 300

Te Apiti WDV110 55 90.2

Tararua BPE334 96 63.36

Total 1031 1603.56

Table 1-3 - North Island Wind-farms


Blenheim BLN110 31 50

Timaru TIM220 182 300

Invercargill INV220 182 300

White Hill NMA33 36 58.68

Total 431 708.68

Table 1-4 - South Island Wind-farms

3 The three existing wind-farms of Tararua, Te-Apiti and White Hills were not scaled for each different generation scenario. Therefore, even the 0% scenario has a small level of wind generation.

4 Actually, Tararua wind farm contains 51x660kW machines connected to BPE0331 and 52x660kW machines connected to LTN033. For modelling purposes, Transpower assumes that all machines are connected to BPE. For the study results, this simplification is not relevant.



1.6 Voltage Sag Screening

1.6.1 Voltage Sag Study Methodology Voltage sag screening was performed for the 20 scenarios. The methodology is as follows:

Assumptions for wind generators:

Each wind generator is a generic fixed speed asynchronous machine with no built in FRT-capability and no fast acting reactive power compensation.

It is assumed that each induction machine provides no contribution to the short circuit power of the grid (no short circuit current)5.

Every wind generator is equipped with an under-voltage relay with a setting a 0.8 p.u and a delay of 50ms. This corresponds to standard settings of low-cost wind generators.

Voltage Sag Screening Methodology:

For each bus bar in the system, calculate a solid (0 Ohm) 3 phase short circuit using the IEC minimum fault method. Initially, only faults in the 220 kV system were considered as these are expected to result in the most widespread voltage depression. The IEC minimum method is chosen because it allows for zero short circuit contributions from asynchronous motor/generators to the fault and hence calculates the lowest and most conservative value for the post fault bus voltages.

For each faulted bus, identify the wind farms that would trip off due to low bus voltage, (defined as < 0.8 p.u) and sum the active power for each of these to give a wind generation tripped value.

Repeat for each scenario.

5 In reality asynchronous machines do provide some short circuit contribution. However, as a worst case assumption, it is assumed that this contribution is negligible. In the dynamic simulations this contribution is naturally captured and considered.



1.6.2 North Island Power System Key Results In Figure 1-1 the observed wind generation trip for each 220 kV bus fault in the North Island system is shown. This is for 100% wind generation capacity with the normal spinning reserve of 350 MW highlighted by the horizontal red line. High load cases are shown in light blue and light load cases in deep red.

Two key points to note are:

In the light load scenarios the amount of wind generation to trip is generally much larger than the corresponding high load scenario. This is expected due to the displacement of more other generation by wind generation and a subsequently lower short circuit level in the light load case.

In most of the cases, the total wind generation trip exceeds the normal spinning reserve of 350MW. In some of the light load cases, all wind generators on the North Island would trip.

0

200

400

600

800

1000

1200

1400

1600

1800

ALB2

20AR

A220

ATI2

20BP

E220

BRB2

20BR

K220

EDG

220

GLN

220

HAM

220

HAY

220

HEN

220

HLY

220

HPI

_220

_1KA

W22

0LT

N_2

20_1

MD

N22

0M

TI22

0N

PL22

0O

HK2

20O

KI22

0O

TA22

0O

TC22

0PE

N22

0PP

I_22

0RD

F220

RPO

220

SFD

220

SPLC

220

SVL2

20SW

N22

0TA

K220

-1TK

U22

0-1

TMN

220

TNG

220

TRK2

20TW

H22

0W

HI2

20W

IL22

0W

KM22

0W

PA22

0W

RK22

0W

TU22

0-1

faulted bus

win

d po

wer

tri

pped

(M

W)

HLLL

Figure 1-1 - wind power tripped by bus, North Island under high wind conditions



Figure 1-2 shows the same chart as Figure 1-1 with the total wind generation at 25% of installed wind generation capacity. The key change is that the total quantity of tripped wind generation has been significantly reduced in comparison with the same faults in the 100% wind generation scenario. The reduction is caused for two reasons. Firstly, there is less total wind generation in the system and therefore the maximum amount to trip is correspondingly less. Secondly, because there is less wind generation, there is more other generation and the short circuit power or system strength is increased across the system, resulting in less widespread voltage depressions following a fault.

0

100

200

300

400

500

600

ALB2

20AR

A220

ATI2

20BP

E220

BRB2

20BR

K220

EDG

220

GLN

220

HAM

220

HAY

220

HEN

220

HLY

220

HPI

_220

_1KA

W22

0LT

N_2

20_1

MD

N22

0M

TI22

0N

PL22

0O

HK2

20O

KI22

0O

TA22

0O

TC22

0PE

N22

0PP

I_22

0RD

F220

RPO

220

SFD

220

SPLC

220

SVL2

20SW

N22

0TA

K220

-1TK

U22

0-1

TMN

220

TNG

220

TRK2

20TW

H22

0W

HI2

20W

IL22

0W

KM22

0W

PA22

0W

RK22

0W

TU22

0-1

faulted bus

win

d po

wer

tri

pped

(M

W)

HLLL

Figure 1-2 - wind power tripped by bus, North Island, low wind conditions



The example shown in Figure 1-3 demonstrates that as the wind generation % increases from 0-100% of installed wind generation capacity, the amount of wind generation to trip after a fault rises approximately proportionately. In this example, only the five 220 kV bus faults with the largest wind generation trip are shown. At 25% of the installed capacity of 1600 MW, the total wind generation to trip will exceed the usual North Island spinning reserve of 350 MW in three of the five fault cases. At a wind generation output of 100% of installed wind generation capacity all five of these example faults cause greater than 350 MW of wind generation to trip.

The reason for the slight non-linearity is because of the displacement of other generation, which provides a contribution to the short circuit level, by wind generation that does not. Here, the large difference between the 75% and 100% cases for the HLY220 and ATI220 faults is caused by some large generation relatively near to the two faults being displaced by wind generation.

0

200

400

600

800

1000

1200

1400

1600

1800

0 25 50 75 100

wind generation %

win

d po

wer

tri

pped

(M

W)

MTI220WKM220TKU220-1HLY220ATI220

faulted bus

Figure 1-3 wind power tripped by wind generation level, North Island high load



1.6.3 South Island Power System Key Results In Figure 1-4 the observed wind generation trip for each 220 kV bus fault in the South Island system is shown. This is for 100% of wind generation capacity with the normal spinning reserve of 120 MW highlighted by the horizontal red line. High load cases are shown in light blue and light load cases in deep red.

Two key points to note are:

For all but five locations, a fault in a light load scenario causes over 700 MW of wind generation to trip, this significantly exceeds the normal South Island spinning reserve of 120 MW.

As for the North Island system, a fault in the light load scenario causes more lost generation than the high load scenario. Despite this, in all but two of the high load cases the amount of wind generation tripped is greater than 300 MW, still about three times larger than the normal South Island spinning reserve.

0

100

200

300

400

500

600

700

800

ASB

AVI_

220

BEN

_220

BRY_

220

CML_

220A

CUT2

20-2

CYD

_220

HW

B_22

0IN

V_22

0IS

L_22

0KI

K_22

0LI

V_22

0M

AN_2

20N

MA_

220

NSY

_220

OH

A_22

0O

HB_

220

OH

C_22

0O

pihi

_1RO

X_22

0SD

N_2

20ST

K_22

0TI

M_2

20A

TIM

_220

BTK

B_22

0TM

H_2

20TW

I_22

0TW

Z_22

0W

TK_2

20W

TT22

0-2

WTT

220-

3

faulted bus

win

d po

wer

trip

ped

(MW

)

HLLL

Figure 1-4 - wind power tripped by bus, South Island, high wind conditions



Figure 1-5 shows the corresponding chart with the wind generation at 25% of installed wind generation capacity. Despite the reduced wind generation, the amount of tripped wind generation still exceeds the normal spinning reserve for a significant majority of the light load cases and several of the high load cases.

0

50

100

150

200

250

ASB

AVI_

220

BEN

_220

BRY_

220

CML_

220A

CUT2

20-2

CYD

_220

HW

B_22

0IN

V_22

0IS

L_22

0KI

K_22

0LI

V_22

0M

AN_2

20N

MA_

220

NSY

_220

OH

A_22

0O

HB_

220

OH

C_22

0O

pihi

_1RO

X_22

0SD

N_2

20ST

K_22

0TI

M_2

20A

TIM

_220

BTK

B_22

0TM

H_2

20TW

I_22

0TW

Z_22

0W

TK_2

20W

TT22

0-2

WTT

220-

3

faulted bus

win

d po

wer

trip

ped

(MW

)

HLLL

Figure 1-5 - wind power tripped by bus, South Island wind generation: 25% of installed wind capacity



As for the North Island cases, Figure 1-6 shows that the amount of wind generation that trips in the South Island increases approximately proportionately as wind generation output increases from 0-100% of installed wind generation capacity. Again, only the five 220 kV bus faults with the largest wind generation trip are shown.

Max of wind power lost (MW) faulted bus (name)

Wind generation (in % of

installed wind power capacity) TWZ_220 CML_220A CYD_220 ROX_220 HWB_220

0% 0 58.7 58.7 58.7 58.7

25% 88.7 210.3 210.3 210.3 134.5

50% 177.5 362 362 362 210.3

75% 261.3 507 507 507 282.9

100% 708.7 658.7 658.7 658.7 358.7

Table 1-5 - wind power tripped by wind generation level, South Island high load

0

100

200

300

400

500

600

700

800

0 25 50 75 100

wind generation %

win

d po

wer

trip

ped

(MW

)

TWZ_220CML_220ACYD_220ROX_220HWB_220

Faulted Bus

Figure 1-6 - wind power tripped by wind generation level, South Island high load

1.6.4 System Impact from Medium Voltage Faults (110 kV) For the initial part of the study, the voltage sag analysis was limited to faults on the 220 kV system, as usually HV faults will cause the most widespread voltage depression and hence the most tripped wind generation. However,



a sensitivity analysis was performed to look at faults in the medium voltage (110 kV) system to see if faults here could also cause large amounts of wind generation to trip.

Figure 1-7 shows the wind power tripped by bus fault for the 30 worst 110 kV system faults for the high wind scenario (100% wind generation). Although the impact is not as severe as for 220 kV faults, the majority of these faults still cause wind power tripping greater than the normal spinning reserve of 350 MW.

Therefore, it is true in general that 220 kV system faults will cause the most wind generation to trip. However, there are still many 110 kV faults that will cause more than 350 MW of wind generation to trip.

0

200

400

600

800

1000

1200

1400

1600

1800

BPE1

10H

AY11

0TK

R11

0U

HT1

10W

IL11

0CP

K110

GFD

110

KWA_

110_

1M

LG11

0N

PL11

0PN

I110

SFD

110

TAP-

110

WD

V110

HEN

110

HEP

110

LST1

10O

TA11

0PA

K110

PEN

110

WIR

110

CST1

10M

TN_1

10_1

ALB1

10M

NG

110

RO

S110

MD

N11

0W

RU

-110

-1G

YT11

0-1

MST

110

faulted bus

win

d po

wer

tri

pped

(M

W)

HLLL

Figure 1-7 - wind power tripped by bus, North Island 100% wind power generation (110 kV)

1.7 Options to reduce wind farm tripping The most effective method to reduce the tripped wind generation after a high voltage fault is to enforce FRT capability for all connected wind farms. Then, wind farms will be able to remain connected to the grid for more severe faults and keep the affected area of the fault small.



In this context, it is interesting to analyzed if full FRT capability, meaning that the wind farm can ride through faults with a remaining voltage of 0p.u., is required or if it would be sufficient to ask wind generators to remain connected for voltages above a certain minimum threshold voltage.

The results of a rough assessment about the minimum required trip voltage are depicted in Figure 1-8. In this example the amount of tripped wind generation in case of a fault at the Whakamaru 220 kV bus (identified in section 1.6.2 as one of the worst case faults in the North Island system) with different wind farm trip voltages is shown. From this figure it can be derived that a trip voltage of 0.2 p.u would be required for ensuring that the amount of lost wind generation does not exceed the normal North Island spinning reserve of 350MW.

0

200

400

600

800

1000

1200

1400

1600

1800

0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8

trip voltage (p.u)

win

d po

wer

tri

pped

(M

W)

HLLL

Figure 1-8 wind power tripped for a fault at WKM220 bus, North Island wind generation: 100% of installed wind generation capacity

2 D y n a m i c W i n d I m p a c t S t u d i e s


2 Dynamic Wind Impact Studies Following the voltage sag screening, dynamic studies have been carried out with the purpose of:

Verifying the amount of tripped wind generation obtained by steady state voltage sag screening.

Analyzing the consequences of tripped wind generation.

2.1 Study Assumptions The dynamic studies follow on from the voltage sag screening. From the voltage sag assessment 30 critical cases were identified for in-depth dynamic simulation, 20 from the North Island and 10 from the South Island. These are shown in Table 2-1.

Case Faulted bus Region Load case Wind %

S_001 WKM220 Edgecume High Load 100

S_002 HLY220 Hamilton High Load 100

S_003 BPE220 Bunnythorpe High Load 100

S_004 HAY220 Wellington High Load 100

S_005 SFD220 Taranaki High Load 100

S_006 ALB220 North Isthmus High Load 100

S_007 OTA220 Auckland High Load 100

S_008 RDF220 Hawkes Bay High Load 100

S_009 HLY220 Hamilton Light Load 100

S_010 OTA220 Auckland Light Load 100

S_011 WKM220 Edgecume Light Load 100

S_012 WIL220 Wellington Light Load 100




S_016 BPE220 Bunnythorpe Light Load 50




S_020 BPE220 Bunnythorpe Light Load 0

S_021 KIK220 Nelson High Load 100

S_022 ISL220 Christchurch High Load 100

S_023 TIM220A Canterbury High Load 100

S_024 TWZ220 Otago High Load 100

S_025 ROX220 Southland High Load 100



S_026 TWZ220 Otago Light Load 100





Table 2-1 Critical Cases for Dynamic Simulation

For more detail on the methodology for the development of the generation scenarios and modelling of the wind generator plant please refer to the modelling report [1].

2.1.1 Wind-farms Besides the three existing wind-farms Te Apiti, Tararua and White Hill, nine new wind-farms are modelled in the North and South Island power systems.

It was assumed that least cost turbines will be used, which corresponds to fixed speed asynchronous generator wind turbines with no FRT capability and no fast acting reactive power compensation.

The wind-farms are shown in the tables below.


Marsden MDN220 91 150

Otahuhu OTA220 182 300

Huntly HLY220 61 100

Hawkes Bay RDF220 182 300

Manawatu BPE220 182 300

Wilton WIL220 182 300

Te Apiti WDV110 55 90.2

Tararua BPE33 96 63.36

Total 1031 1603.56

Table 2-2 - North Island Wind-farms


Blenheim BLN110 31 50

Timaru TIM220 182 300

Invercargill INV220 182 300

White Hill NMA33 36 58.68

Total 431 708.68

Table 2-3 - South Island Wind-farms



2.2 Dynamic Simulation of the NZ System

2.2.1 Dynamic Study Methodology The methodology for the dynamic simulations is as follows:

Assumptions for wind generators:

Each wind generator is modelled by a generic fixed speed asynchronous machine with no FRT capability and no fast acting reactive power compensation.

Every wind generator is equipped with an under-voltage relay with a setting of 0.8 p.u and a delay of 50 ms. This relay is located on the LV side of the wind generator unit transformer. This assumption corresponds to typical under-voltage protection settings used in low cost wind turbines.

Aggregated models have been used for every wind-farm.

Assumptions for the power system:

Synchronous generator plants AVR and governor systems are as per the data provided in the DIgSILENT cases by Transpower.

Several of the smaller units are without any control systems, AVR or governor as these were not implemented in the model provided by Transpower. Therefore, they have constant excitation voltage and constant turbine power.

Power system loads were represented by a constant current characteristic for the active part and constant impedance characteristic for the reactive part.

The HVDC link was modelled as a constant current source/load for both active and reactive power.

Dynamic Simulation Methodology:

For each of the 30 critical cases perform a 5 second dynamic simulation with a 0 Ohm three phase fault for 120 ms at the specified bus.

Record important variables such as total wind power, total synchronous generator power, key line flows, bus voltages etc.

Repeat for each scenario.



2.3 Summary of Dynamic results for the North Island

2.3.1 Wind Generation Tripping The loss of wind generation predicted in many fault cases by the static analysis is also observed in the dynamic analysis.

Figure 2-1 shows a comparison of the predicted wind generation trip (steady state voltage sag screening) to the wind generation trip observed with dynamic analysis for the North Island system. For the majority of the cases, the estimate for the amount of wind generation to trip obtained by static analysis is confirmed by the dynamic simulations.

0

200

400

600

800

1000

1200

1400

1600

1800

S_00

1S_

002

S_00

3S_

004

S_00

5S_

006

S_00

7S_

008

S_00

9S_

010

S_01

1S_

012

S_01

3S_

014

S_01

5S_

016

S_01

7S_

018

S_01

9S_

020

Case

Win

d Po

wer

Trip

ped

(MW

)

Static analysis wind power tripped Dynamic simulation wind power tripped

Figure 2-1 Static and dynamic analysis comparison, wind power tripped, North Island



2.3.2 Electrical frequency at Huntly The main consequence of the disconnection of large amounts of wind generation is large frequency drops. According to part C of the New Zealand Electricity Governance Rules [2], the following automatic under frequency load shedding (AUFLS) exists for the North Island:

Block 1, frequency



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1200.00

1000.00

NIPS: Generation, Active Power in MW

5.003.752.501.250.00 [s]

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875.00

750.00

625.00

500.00

375.00

250.00

WindFarms: Generation, Active Power in MW

5.003.752.501.250.00 [s]

51.00

50.00

49.00

48.00

47.00

HLY-UN1: Electrical Frequency in Hz

Y = 47.800 Hz

Y = 47.500 Hz

DIGSILENT Transpower Wind Impact Study Pgen_sum

3 phase fault at bus BPE220, cleared after 120ms S_016_Light Load Wind Penetration 50%

Date: 9/28/2006

Annex: 16 /4

DIg

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Figure 2-2 - Case S_016, example of excessive frequency drop due to tripped wind generation



2.3.3 Short term voltage instability, North Island Besides frequency collapse, the sudden disconnection of large amounts of wind generators can cause high branch flows exceeding the voltage stability limit and finally leading to voltage collapse.

In the light load, high wind cases S_009-S_012 and S_015, short term voltage instability was observed. In case S_015 this could probably be avoided by load shedding. However, in the other four cases the voltage collapse occurs almost immediately after the tripping of the wind generation the load shedding would not operate in time and a system collapse is inevitable.

Figure 2-3 shows an example from simulation S_012. This case shows how the initial voltage collapse initiates the subsequent trip of more and more wind generators and finally drives the system into a complete collapse. Load shedding would be initiated too late.



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1600.00

1200.00

800.00

400.00

NIPS: Generation, Active Power in MW

5.003.752.501.250.00 [s]

2000.00

1600.00

1200.00

800.00

400.00

0.00

-400.00

WindFarms: Generation, Active Power in MW

5.003.752.501.250.00 [s]

60.00

50.00

40.00

30.00

20.00

10.00

HLY-UN1: Electrical Frequency in Hz

Y = 47.800 HzY = 47.500 Hz

DIGSILENT Transpower Wind Impact Study Pgen_sum

3 phase fault at bus WIL220, cleared after 120ms S_012_Light Load Wind Penetration 100%

Date: 9/28/2006

Annex: 12 /4

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Figure 2-3 - Simulation S_012, example short term voltage instability



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1.00

0.90

0.80

0.70

0.60

WGbus: Voltage, Magnitude in p.u.WF2_G1: Voltage, Magnitude in p.u.WF3_G3: Voltage, Magnitude in p.u.WF4_G1: Voltage, Magnitude in p.u.WF5_G1: Voltage, Magnitude in p.u.TAPG(1): Voltage, Magnitude in p.u.WF6_G1: Voltage, Magnitude in p.u.TWF terminal: Voltage, Magnitude in p.u.

Y = 0.800 p.u.

DIGSILENT Transpower Wind Impact Study WG_voltage

3 phase fault at bus WIL220, cleared after 120ms S_012_Light Load Wind Penetration 100%

Date: 9/28/2006

Annex: 12 /2

DIg

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2.3.4 Interconnecting line flows, North Island In cases, where power is imported into areas with high amounts of wind generation, there is a high risk of either long term voltage collapse or thermal overload problems of interconnecting circuits. For a detailed analysis, PV-curve analysis based on subsequent load flow calculations or long-term simulations would have to be carried out considering the post-contingency network state (considering the tripped wind generators).

2.4 Summary of dynamic results for the South Island

2.4.1 Sudden Loss of Wind Generation The loss of wind generation predicted in many fault cases by the static analysis is also observed in the dynamic analysis.

Figure 2-5 shows a comparison of the predicted wind generation trip (steady state voltage sag screening) to the observed wind generation trip (dynamic analysis) for the South Island system. With the exception of cases S_024 and S_025, the dynamic analysis confirms exactly the results of the static estimate.

0

100

200

300

400

500

600

700

800

S_021 S_022 S_023 S_024 S_025 S_026 S_027 S_028 S_029 S_030

Case

Win

d G

ener

atio

n Tr

ippe

d (M

W)

Static analysis wind power tripped Dynamic simulation wind power tripped

Figure 2-5 - Static and dynamic analysis comparison, wind power tripped, South Island



2.4.2 Electrical frequency at Clyde In many of the simulations large frequency drops were observed due to the disconnection of large amounts of wind generation. According to part C of the New Zealand Electricity Governance Rules [2], the following automatic under frequency load shedding (AUFLS) exists for the South Island:

Block 1, frequency



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SIPS: Generation, Active Power in MW

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300.00

200.00

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-100.00

Windfarms: Generation, Active Power in MW

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52.00

50.00

48.00

46.00

44.00

42.00

CYD_G1: Electrical Frequency in Hz

Y = 47.500 Hz 1.472 s

Y = 45.500 Hz

DIGSILENT Transpower Wind Impact Study PGen_sum

3 phase fault at bus TWZ_220, cleared after 120ms S_028_Light Load Wind Penetration 50%

Date: 9/28/2006

Annex: 28 /4

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Figure 2-6 - Case S_028, example of excessive frequency drop due to tripped wind generation



2.4.3 Short term voltage instability, South Island In the light load, high wind case S_026, a short term voltage instability was observed. This occurs almost immediately after the tripping of the wind generation the load shedding blocks at 47.5 Hz and 45.5 Hz would not operate in time and a system collapse is inevitable.

A voltage instability was also observed in simulation S_028 after 2 seconds simulation time. However, the first load shedding block would have activated before this and probably prevented it from occurring.

Figure 2-3 shows an example from simulation S_026, in which the system loses synchronism immediately after the disconnection of large amounts of wind generation.



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0.90

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PCC_BLN_WF: Voltage, Magnitude in p.u.PCC_INV_WF: Voltage, Magnitude in p.u.NMA_PCC: Voltage, Magnitude in p.u.PCC_TIM_WF: Voltage, Magnitude in p.u.

DIGSILENT Transpower Wind Impact Study PCC_Voltage

3 phase fault at bus TWZ_220, cleared after 120ms S_026_Light Load Wind Penetration 100%

Date: 9/28/2006

Annex: 26 /1

DIg

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2.4.4 Interconnecting line flows South Island As for the North Island simulations, thermal overload problems can potentially occur during times in which power is imported into areas with high amount of wind generation. Following the sudden loss of wind generation, the power flow into this area is increased, leading either to voltage stability problems or thermal overloads of the interconnecting circuits.

A detailed analysis either based on long-term simulations or on PV-curve analysis was beyond the scope of this study.

3 C o n c l u d i n g R e m a r k s a n d R e c o m m e n d a t i o n s


3 Concluding Remarks and Recommendations For analyzing the impact of increased levels of wind generation in New Zealand, detailed system impact studies have been carried out.

In this first stage of the project, it has been assumed that least cost wind generators without fault ride-through capability are used for all wind farms in New Zealand.

As a first step, the potential risk of widespread tripping of wind generation following single contingent events has been assessed using steady state voltage sag screening. In a second step, the most critical cases have been simulated dynamically to confirm the results of the voltage sag screening and to analyze the consequences of widespread tripping of wind generation.

The voltage sag screening has shown that many single contingent events, such as faults on single transmission circuits can lead to widespread tripping of wind generation if wind generators do not have the ability to ride through voltage sags.

Dynamic simulations show that widespread tripping of wind generation can drive the system into frequency stability problems causing load shedding or dynamic voltage stability problems.

However, increasing spinning reserve and system inertia requires that almost all wind generators are backed up by non-wind generators, which leads to enormous additional spinning reserve. Besides this, the network must be able to transport any additionally required reserve power. In this study, a number of cases were identified, where the available transport capacity is not sufficient and consequently, the network runs into dynamic voltage collapse. For avoiding this, network reinforcements would be required or inter-area power transfer must be limited.

The second option, only allowing wind generators with FRT-capability, is fairly easy to realize because this kind of wind generator is standard technology. Consequently, for avoiding drastically reduced reliability of supply in the New Zealand power system there is only one practical solution:

Only allowing the connection of wind generators with FRT-capability.

This has become an international standard for power transmission systems with high wind penetration, e.g. in Germany, Denmark, U.K. or Australia.

When connecting wind generators with FRT capability, additional reserve power is only required for backing up wind fluctuations but not for backing up wind generator trips.

4 R e f e r e n c e s


4 References [1] Assessment of Potential Security Risks due to High Levels of Wind Generation in New Zealand - Stage 1, Modelling Report.

[2] Electricity Governance Rules, Part C, Common Quality 8 June 2006


A N N E X E S

Annexes


Annex A-1: Results of Voltage Sag Screening


Max of wind power lost (MW) Wind Generation (in % of installed wind generation capacity)

faulted bus (name) 0% 25% 50% 75% 100%

ALB220 0 138.3 278.3 411.7 550

ARA220 0 75.8 151.6 224.2 663.4

ATI220 0 75.8 151.6 224.2 963.4

BPE220 153.6 305.2 456.9 601.9 753.6

BRB220 0 113.7 227.5 336.3 450

BRK220 153.6 305.2 456.9 601.9 753.6

EDG220 0 75.8 151.6 224.2 300

GLN220 0 138.3 278.3 411.7 550

HAM220 0 100.4 278.3 411.7 550

HAY220 153.6 305.2 456.9 601.9 753.6

HEN220 0 138.3 278.3 411.7 550

HLY220 0 138.3 278.3 411.7 1003.6

HPI_220_1 0 138.3 278.3 411.7 550

KAW220 0 0 0 0 300

LTN_220_1 153.6 305.2 456.9 601.9 753.6

MDN220 0 113.7 227.5 336.3 450

MTI220 153.6 418.9 735.1 1013.6 1603.6

NPL220 153.6 305.2 456.9 601.9 753.6

OHK220 0 75.8 151.6 224.2 300

OKI220 0 75.8 151.6 224.2 300

OTA220 0 138.3 278.3 411.7 550

OTC220 0 138.3 278.3 411.7 550

PEN220 0 138.3 278.3 411.7 550

PPI_220 0 75.8 151.6 224.2 663.4

RDF220 0 75.8 151.6 224.2 300

RPO220 0 75.8 151.6 224.2 663.4

SFD220 153.6 305.2 456.9 601.9 753.6

SPLC220 153.6 305.2 456.9 601.9 753.6

SVL220 0 113.7 227.5 336.3 450

SWN220 0 138.3 278.3 411.7 550

TAK220-1 0 138.3 278.3 411.7 550

TKU220-1 153.6 381 608.5 826.1 1053.6

TMN220 0 0 0 0 0

TNG220 153.6 229.4 305.2 377.7 753.6

TRK220 0 75.8 151.6 224.2 300

TWH220 0 24.6 202.5 299.6 400

WHI220 0 75.8 151.6 224.2 300

WIL220 153.6 305.2 456.9 601.9 753.6

WKM220 153.6 519.4 886.8 1237.8 1603.6

WPA220 0 75.8 151.6 224.2 600


WRK220 0 75.8 366.7 511.7 753.6

WTU220-1 0 75.8 151.6 224.2 300

Table 4-1 - Voltage Sag Results, North Island High Load


faulted bus (name) 0% 25% 50% 75% 100%

ALB220 63.4 443.5 886.8 1237.8 1603.6

ARA220 153.6 481.4 886.8 1237.8 1603.6

ATI220 153.6 519.4 886.8 1237.8 1603.6

BPE220 153.6 381 659.3 1125.7 1453.6

BRB220 0 138.3 278.3 411.7 1303.6

BRK220 153.6 305.2 659.3 901.5 1453.6

EDG220 0 381 608.5 826.1 1453.6

GLN220 153.6 443.5 886.8 1237.8 1603.6

HAM220 153.6 519.4 886.8 1237.8 1603.6

HAY220 153.6 305.2 456.9 826.1 1053.6

HEN220 153.6 519.4 886.8 1237.8 1603.6

HLY220 153.6 519.4 886.8 1237.8 1603.6

HPI_220_1 153.6 443.5 886.8 1237.8 1603.6

KAW220 0 290.8 608.5 826.1 1453.6

LTN_220_1 153.6 305.2 608.5 826.1 1453.6

MDN220 0 138.3 278.3 411.7 1603.6

MTI220 153.6 519.4 886.8 1237.8 1603.6

NPL220 153.6 305.2 456.9 901.5 1153.6

OHK220 153.6 519.4 886.8 1237.8 1603.6

OKI220 153.6 381 811 1237.8 1603.6

OTA220 153.6 519.4 886.8 1237.8 1603.6

OTC220 153.6 519.4 886.8 1237.8 1603.6

PEN220 153.6 519.4 886.8 1237.8 1603.6

PPI_220 153.6 519.4 886.8 1237.8 1603.6

RDF220 0 75.8 608.5 826.1 1053.6

RPO220 153.6 381 608.5 826.1 1053.6

SFD220 153.6 329.8 507.7 901.5 1453.6

SPLC220 153.6 329.8 507.7 901.5 1453.6

SVL220 0 138.3 735.1 1237.8 1603.6

SWN220 153.6 519.4 886.8 1237.8 1603.6

TAK220-1 153.6 519.4 886.8 1237.8 1603.6

TKU220-1 153.6 481.4 811 1237.8 1603.6

TMN220 153.6 305.2 456.9 677.3 853.6

TNG220 153.6 381 608.5 826.1 1053.6

TRK220 153.6 381 811 1237.8 1603.6

TWH220 153.6 443.5 886.8 1237.8 1603.6

WHI220 0 75.8 608.5 826.1 1053.6

WIL220 153.6 305.2 456.9 826.1 1053.6

WKM220 153.6 519.4 886.8 1237.8 1603.6

WPA220 153.6 519.4 886.8 1237.8 1603.6


WRK220 153.6 519.4 886.8 1237.8 1603.6

WTU220-1 0 75.8 518.3 826.1 1053.6

Table 4-2 - Voltage Sag Results, North Island Light Load


faulted bus (name) 0% 25% 50% 75% 100%

ASB 0 88.7 177.5 261.3 350

AVI_220 0 88.7 177.5 261.3 350

BEN_220 0 88.7 177.5 261.3 350

BRY_220 0 88.7 177.5 261.3 350

CML_220A 58.7 210.3 362 507 658.7

CUT220-2 0 88.7 177.5 261.3 350

CYD_220 58.7 210.3 362 507 658.7

HWB_220 58.7 134.5 210.3 282.9 358.7

INV_220 58.7 134.5 210.3 282.9 358.7

ISL_220 0 88.7 177.5 261.3 350

KIK_220 0 12.9 25.8 37.1 50

LIV_220 0 88.7 177.5 261.3 350

MAN_220 58.7 134.5 210.3 282.9 358.7

NMA_220 58.7 134.5 210.3 282.9 358.7

NSY_220 0 0 0 0 0

OHA_220 0 88.7 177.5 261.3 350

OHB_220 0 88.7 177.5 261.3 350

OHC_220 0 88.7 177.5 261.3 350

Opihi_1 0 88.7 177.5 261.3 350

ROX_220 58.7 210.3 362 507 658.7

SDN_220 58.7 134.5 210.3 282.9 358.7

STK_220 0 12.9 25.8 37.1 50

TIM_220A 0 88.7 177.5 261.3 350

TIM_220B 0 88.7 177.5 261.3 350

TKB_220 0 88.7 177.5 261.3 350

TMH_220 58.7 134.5 210.3 282.9 358.7

TWI_220 58.7 134.5 210.3 282.9 358.7

TWZ_220 0 88.7 177.5 261.3 708.7

WTK_220 0 88.7 177.5 261.3 350

WTT220-2 0 88.7 177.5 261.3 350

WTT220-3 0 88.7 177.5 261.3 350

Table 4-3 - Voltage Sag Results, South Island High Load



faulted bus (name) 0% 25% 50% 75% 100%

ASB 0 223.2 387.8 544.1 708.7

AVI_220 58.7 223.2 387.8 544.1 708.7

BEN_220 58.7 223.2 387.8 544.1 708.7

BRY_220 0 88.7 387.8 544.1 708.7

CML_220A 58.7 223.2 387.8 544.1 708.7

CUT220-2 0 88.7 177.5 261.3 350

CYD_220 58.7 223.2 387.8 544.1 708.7

HWB_220 58.7 223.2 387.8 544.1 708.7

INV_220 58.7 223.2 387.8 544.1 708.7

ISL_220 0 223.2 387.8 544.1 708.7

KIK_220 0 88.7 177.5 261.3 350

LIV_220 58.7 223.2 387.8 544.1 708.7

MAN_220 58.7 223.2 387.8 544.1 708.7

NMA_220 58.7 223.2 387.8 544.1 708.7

NSY_220 58.7 223.2 387.8 544.1 708.7

OHA_220 58.7 223.2 387.8 544.1 708.7

OHB_220 58.7 223.2 387.8 544.1 708.7

OHC_220 58.7 223.2 387.8 544.1 708.7

Opihi_1 0 223.2 387.8 544.1 708.7

ROX_220 58.7 223.2 387.8 544.1 708.7

SDN_220 58.7 223.2 387.8 544.1 708.7

STK_220 0 88.7 177.5 261.3 350

TIM_220A 0 88.7 177.5 544.1 708.7

TIM_220B 0 88.7 177.5 544.1 708.7

TKB_220 58.7 223.2 387.8 544.1 708.7

TMH_220 58.7 223.2 387.8 544.1 708.7

TWI_220 58.7 223.2 387.8 544.1 708.7

TWZ_220 58.7 223.2 387.8 544.1 708.7

WTK_220 58.7 223.2 387.8 544.1 708.7

WTT220-2 0 88.7 177.5 261.3 350

WTT220-3 0 88.7 177.5 261.3 350

Table 4-4 - Voltage Sag Results, South Island Light Load

Investigation-7-8-9(1)

Documents

Transcript of Investigation-7-8-9(1)