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Main Transmission Planning Criteria

Main Transmission System Planning

Guideline

February, 2005

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1. INTRODUCTION................................................................................................. 1

2. RELIABILITY ......................................................................................................1

2.1 DEFINITION........................................................................................................1

2.2 CRITERIA ...........................................................................................................2

2.2.1 Single contingency criterion......................................................................2

2.2.2 Maintenance outage................................... Error! Bookmark not defined.

An underlying assumption of the N-1 criteria is that maintenance is carried out

during times of light load. ....................................... Error! Bookmark not defined.

2.2.3 Multiple contingency.................................................................................. 3

2.2.4 Sub-station arrangement............................................................................3

2.3 RELIABILITY ASSESSMENT ................................................................................3

2.3.1 Load ...........................................................................................................3

2.3.2 Dispatch.....................................................................................................3

3. STEADY STATE PERFORMANCE CRITERIA ............................................. 4

3.1 EQUIPMENT RATINGS ........................................................................................4

3.1.1 Grid owner equipment ...............................................................................4

3.1.2 Generating Unit Rating..............................................................................4

3.2 VOLTAGE QUALITY ...........................................................................................4

3.2.1 Normal Steady State Voltage ..................................................................... 5

3.2.2 Step Change in Voltage - Dynamic............................................................5

3.3 SHORT CIRCUIT LEVELS .....................................................................................6

4. STABILITY CRITERIA ...................................................................................... 6

4.1 TRANSIENT STABILITY.......................................................................................6

4.1.1 Disturbances selected for testing...............................................................7 4.1.2 Auto-reclose of Circuit Breakers ...............................................................7

4.1.3 Fault Clearing Time...................................................................................8

4.1.4 Transient Voltage Performance Criterion.................................................8

4.1.5 Over-voltages due to Load Rejection.........................................................8

4.2 DYNAMIC STABILITY.........................................................................................9

4.3 VOLTAGE STABILITY .........................................................................................9

4.4 FREQUENCY STABILITY .............................ERROR! BOOKMARK NOT DEFINED.

APPENDIX A: SECURITY CRITERIA ................................................................. 12

APPENDIX B: INFREQUENT SWITCHING CRITERIA ..................................15

APPENDIX C: TRANSIENT STABILITY DISTURBANCES ............................ 16

APPENDIX D: DAMPING CRITERIA FOR DYNAMIC STABILITY .............18

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1. Introduction

The purpose of transmission system planning is to develop a reliable and efficient

transmission system for transferring power from areas of generation to areas of

demand (load) under varying system conditions, while operating equipment within

accepted ratings. The system conditions include - changing demand patterns,

generation changes and equipment outages (planned or unplanned).

The planning process involves applying a number of criteria: technical, economic,

environmental and safety to the current or future transmission system. This document

sets out the technical criteria to be applied in planning the main transmission network.

While this document is focused on technical criteria only, readers are reminded that

any proposed transmission development must also consider all other planning aspects

– such as environmental, economic, etc.

The technical criteria used in transmission system planning can be divided into three

main categories, which are covered in this Guideline as per Table 1.1:

Table 1.1: Technical Criteria

Category Defined as Section

System reliability Is the system adequate and secure? 2

Steady state

performance

Is the normal operating state of the system

within prescribed limits?

3

Stability Does the system remain “normal” or return to

normal following a “disturbance”?

4

Additionally, for comparison purposes, the Appendices provide an international

context to the standards and criteria that Transpower applies in meeting each of these

activities.

2. System Reliability

2.1 Definition

The accepted definition of transmission system reliability incorporates assessment of

two basic aspects of the system - adequacy and security. The National Electricity

Reliability Council, USA (NERC)1

has defined these terms to mean:• Adequacy – The ability of the electric systems to supply aggregate electrical

demand and energy requirements of their customers at all times, taking into

account scheduled and reasonably expected unscheduled outages of system

elements; and

• Security – The ability of the electric systems to withstand sudden disturbances such

as electric short circuits or unanticipated loss of system elements.

1 The National Electricity Reliability Council oversees and co-ordinates reliability and security for the

entire United States.

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2.2 Criteria

Transpower uses a deterministic approach to planning. This approach is consistently

applied in most transmission networks throughout the world.2

The deterministic planning criteria uses N, (N-‘k’) terminologies to describe the

service level for which a system is planned, where ‘k’ is the number of elements outof service at any one time. These terms are defined as follows:

• ( N) criterion denotes that the system is planned such that with all transmission

facilities in service the system is in a satisfactory state and loads may have to be

shed to return to a satisfactory state for a credible contingency event. It could be

said that an N security policy results in a system that is not secure against

contingent events.

• (N-‘k’) criterion denotes that the system is planned such that with all transmission

facilities in service the system is in a secure state and for any ‘k’ credible

contingency event(s) the system moves to a satisfactory state. If any further

contingency events were to occur loads may have to be shed to return to asatisfactory state.

2.2.1 Single contingency criterion

The main interconnected transmission system shall be designed to maintain N-1

security criterion, meaning that the system is in a secure state with all transmission

facilities in service and in a satisfactory state under credible contingent events. N-1 is

a common security standard in many countries including Australia, Ireland, Denmark

and France3. The single contingencies to be considered under an N-1 criterion are:

• loss of a single transmission circuit

• loss of a single generator

• loss of an HVDC pole

• loss of a single bus section

• loss of an interconnecting transformer

• loss of a single shunt connected reactive component, e.g. capacitor bank, SVC

The loss of an element could be either planned (as part of scheduled maintenance) or

unplanned (as an unforeseen event) either by inadvertent disconnection or as a

consequence of a fault occurring in/on the affected element.

2.2.2 Maintenance outagesAn underlying assumption of the N-1 criteria is that maintenance is carried out during

times of light load so that the risk and consequences of an interruption due to

unforseen events is minimised.

2

A 1992 survey by CIGRE confirmed that of 24 countries participating, all used the deterministiccriteria3 Refer to Appendix A for further detail.

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2.2.3 Multiple contingency

The risk and consequences of less frequent but more extreme credible contingencies

must also be investigated to determine what emergency measures may be required to

minimise the consequences and provide for restoration of supply in the shortest

possible time.

2.2.4 Sub-station arrangement

The sub-station arrangements are chosen to satisfy all the reliability performance

criteria set out in this guideline while allowing for future extensions and maintenance.

2.3 Reliability Assessment

Reliability is assessed by simulating performance of the system with all transmission

facilities in service and then applying credible contingencies to the simulation, while

generation and load patterns are varied to determine whether a satisfactory state for

the system may be maintained for the various generation and load patterns.

2.3.1 Load

All simulation studies shall be performed for system peak load conditions for both

summer and winter periods. Studies may also be performed for light load conditions

where required. These latter studies may be necessary, for example, where

experience has identified that certain system issues arise only under light or trough

load conditions.

If a part of the system is radial, the studies for the radial part of the system must be

carried out for peak load conditions for that area.

2.3.2 Dispatch

Simulation studies shall be carried out for the worst case credible generation dispatch

scenarios. For hydro generation (New Zealand’s main source of electricity), these

include dry, average and wet hydrological scenarios.4

Studies shall also be carried out

for extreme dry scenarios to identify emergency measures that may have to be put in

place.

4 These have been developed within Transpower using information from a number of sources including

NIWA

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3. Steady State performance

The steady state criteria apply to normal operating conditions and to post-disturbance

conditions once the system settles to new operating conditions. The steady stateperformance criteria for planning are:

Primary transmission equipment must operate within normal ratings when

all transmission facilities are in service.

⎯

⎯

⎯

⎯

⎯

⎯

⎯

⎯

Primary transmission equipment must operate within acceptable short term

ratings during contingencies.

There is no load curtailment required to maintain N-1 security level for

any operating condition.

Voltage quality is maintained as set out in section 3.2

Cascading outages do not occur.

3.1 Equipment Ratings

3.1.1 Grid owner equipment

The grid owner equipment ratings used are drawn from Transpower’s Asset

Capability Information (ACI) database. The ratings for equipment in this database are

in accordance with Transpower policy document TP.GG.01.10 on equipment ratings,

which take into account manufacturer’s recommendations, the age of equipment and

local environmental conditions. The database includes all transmission equipment:

lines, transformers, switchgear, protection and reactive equipment - synchronous

condensers, capacitors, reactors and SVCs.

3.1.2 Generating Unit Rating

The rating of all generating units connected to the grid shall be the ratings provided

by the Generators as part of their Asset Capability Statement provided to Transpower

( as the Grid Owner).

3.2 Voltage Quality

The criteria for voltage in steady state operation are defined by limits set for different

conditions:

Normal steady state voltage

Step change in voltage

Sustained steady state voltage (after tap changing, Reactive Power Controller

and other dynamic sources actions )

These are discussed in the following subsections.

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3.2.1 Normal Steady State Voltage

The normal steady state voltage at buses shall be as specified in Table 3.1 or as

stipulated in the contract agreement with the customer. Table 3.1 is consistent with

the steady state voltage limits as prescribed in Rule 3.1, Section III, Part C of theElectricity Governance Rules and Regulations (EGRS).

Table: 3.1 Voltage Limits During Normal Conditions

Nominal

Voltage

(kV)

Maximum

Voltage

(kV)

Minimum

Voltage

(kV)

220 242 198

110 121 99

66 69.3 62.7

50 52.5 47.5

3.2.2 Step Change in Voltage - Dynamic

The voltage step change is the dynamic voltage change between the pre-switching

voltage and the prevailing voltage in the period immediately after transient decay and

AVR action but before any manual or slow control action – e.g. manual tap changing,

automatic tap changing, manual switching of capacitor banks under normal operating

conditions. The allowable voltage deviation depends on the frequency of switching –

infrequent or routine.

3.2.2.1 Routine Switching The Australasian standard

5for acceptable voltage deviation during routine switching

is set out in Table 3.2:

Table 3.2 Allowable Dynamic Voltage Deviation

r

no of events per hour

Vdyn/Vn

(%)

MV HV

r ≤ 1 4 3

1 < r ≤ 10 3 2.5

10< r ≤ 100 2 1.5

100 < r ≤ 1000 1.25 1

Note: MV refers to 1 kV < VN ≤ 35 kV

MV refers to 35 kV < VN ≤ 230 kV

Vdyn/Vn – Maximum voltage change for normal operating conditions

The voltage change at buses for routine switching of equipment to control voltage

(e.g. switching of capacitor banks or circuits) must not exceed the value given in

Table 3.2. Currently Transpower plans on the basis of a 2% voltage dip for routine

switching - this is slightly more conservative than set out in the AS/NZS standard.

5 Australian/New Zealand Standard - AS/NZS 61000.3.7:2001,

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3.2.2.2 Infrequent switching

There are no standards specifying the allowable voltage deviation for infrequent

switching, but it would naturally be greater than for routine switching operations.

Transpower has designed the system based on a 5% variation. Worldwide, the

allowable voltage deviation is 5% to 6% depending on the utility.6

3.3 Short circuit levels

The default planned maximum short circuit levels are shown in Table 3.3. There are a

limited number of locations, such as Otahuhu 110 kV and Islington 66 kV buses,

where the maximum fault levels will exceed the default maximum short circuit levels

shown, and these are documented in other Grid Owner documents.

Table 3.3 - Maximum Short Circuit Power and Current Limits

Nominal

Voltage

Maximum short-circuit

Power and Current Limits

kV MVA kA

220 12,000 31.5

110 6,000 31.5

66 1,800 16

50 1,350 16

33 1,400 25

22 950 25

11 475 25

4. Stability Criteria

The stability of a power system is determined by its ability to remain stable when the

system is subjected to any disturbance. It can be further divided into four categories of

stability:

•

•

•

•

Transient Stability

Dynamic Stability

Voltage Stability

Frequency Stability.

These are discussed in the following subsections.

4.1 Transient Stability

Transient stability refers to the ability of the system to maintain synchronism when it

experiences large disturbances like a line fault or loss of a generator.

6 Refer to Appendix B for further information

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Appendices

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also allows for outage of any section of a 132 kV busbar. It does not allow for the

outage of two 330 kV cables, as this is considered too costly.

Supply to the Melbourne and Adelaide CBD’s are designed to meet N-2 criteria.

The 110 kV supply to the Brisbane CBD is being planned so that full supply is

maintained with two 110 kV cables out of service.

United States - Western Electric Co-ordinating Council (WECC),

WECC also uses (N-2) criterion for planning the transmission grid. However, there

are some differences in defining contingencies:

WECC considers bus section outage as a double contingency not a single

contingency.

◊

◊ WECC allows for unplanned outage of two elements with planned load

curtailment or shedding but does not specify the percentage of load that is met

under such conditions.

United Kingdom - National Grid Company (NGC)

The security standard adopted by NGC for the main interconnected transmission

system is (N-2). However, there are significant differences between the NGC system

and the New Zealand system; the NGC system is heavily meshed with generation in

diverse areas, whereas the New Zealand system is comprised of a weak, longitudinal

transmission with significant generation located in a few areas, remote from the

demand. In addition, the NGC demand is around 10 times that of NZ and due to its

density, there are generally alternative supply options to any grid off-take, via the

distribution networks, which means the restoration times can be reduced.

Table A.2 Security Level for Group Demand

Initial System ConditionGroup

Demand Intact System With Single Arranged Outage

Over 1500 MW In accordance with main interconnected transmission system planning criteria

Over 300 MW

To 1500 MW

Immediately

No loss of supply

Note 1

Immediately

Maintenance Period Demand

Within time to restore arranged outage

Group Demand

Over 60 MW

To 300 MW

Immediately

Group Demand minus 20 MW

Note 2

Within 3 hrs

No loss of supply

Within 3 hrs

Smaller of (Group Demand minus

100 MW) and 1/3 Group Demand.

Within time to restore arranged outage

Group Demand

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Appendix B: Infrequent Switching Criteria

Australia

Western Australia uses +/-6% voltage change for infrequent switching whereas the

regulator overseer - NEC does not make any specific distinction between routine and

infrequent switching. Specifically, the NEC code specifies in Clause S5.3.7 that

voltage should not exceed the following limit:

• Where only one Distribution Network Service Provider or Customer has a

connection point associated with the point of supply, the limit is 80% of the

threshold of perceptibility set out in Figure 1 of AS2279 Part 4; or

• Where two or more Distribution Network Service Providers or Customers causing

voltage fluctuations have a connection point associated with the point of supply,

the threshold of perceptibility limit is to be shared in a manner to be agreed

between the Distribution Network Service Provider and the Code Participant inaccordance with good electricity industry practice.

Ireland

ESB National Grid (Ireland) allows step voltage changes of 3% for capacitor bank

switchings with all transmission facilities in service. It does not specify any step

voltage change for infrequent switchings.

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CIGRE

CIGRE published a report in 1992 on a survey carried out on standards used in

transmission planning. Of the 24 countries participating, 20 (83%) confirmed use of

3-phase faults to test stability. Other findings included:

• Australia, Brazil and CIS (formerly part of USSR) countries do not plan for 3-phase faults. Australia and CIS use two-phase-to-ground faults and Brazil uses

single phase faults.

• Some countries consider two-phase faults and single phase faults to assess the

effect of torsional interaction and voltage transients to generators and industrial

users.

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Appendix D: Damping Criteria for Dynamic Stability

The following table compares the criteria across a number of electricity utilities:

Utility Damping Criteria

Transgrid, VENCorp,

Electranet, Western Power

(Australia)

Halving time of the least damped oscillations must

not be more than 5 seconds.

Powerlink Damping ratio of at least 0.05

Elsam (Denmark) Oscillations to be damped within 10-20 seconds

Statnet (Norway) Oscillations to be damped within 10-20 seconds

ESB (Ireland) Damping coefficient of not less than 0.05

UK Power frequency oscillations time constant should

be less than 12 seconds

WECC, (USA) Do not include specific requirement. It is updated

from time to time.

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