Malaysia Transmission

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Transmission System

Reliability Standards

Effective January 1, 2006

Version 2.0Edition 1.0

TENAGA NASIONAL BERHAD, 2006


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Transmission System Reliability Standards Contents

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Contents

TRANSMISSION SYSTEM RELIABILITY STANDARDS ........................................1

CONTENTS........................................................................................................................1

CHAPTER 1: INTRODUCTION.....................................................................................4

1.1 GENERAL ..............................................................................................................41.2 APPLICATIONS AND OBJECTIVES OF THE STANDARDS...........................................51.3 SCOPE ...................................................................................................................6

CHAPTER 2: GENERATION RELIABILITY STANDARD ......................................8

2.1 GENERATION PLANNING SECURITY CRITERIA ......................................................82.2 REQUIREMENTS ASSOCIATED WITH LOSS OF POWER INFEED................................82.3 GENERATION CONNECTION CRITERIA...................................................................9

2.3.1 General Generation Connection Requirements...............................................92.3.2 Planning Criteria for Generation Connections.............................................102.3.3 Operational Criteria for Generation Connections ........................................13

CHAPTER 3: TRANSMISSION RELIABILITY STANDARD.................................14

3.1 GENERAL ............................................................................................................143.2 TRANSMISSION ADEQUACY AND SECURITY CRITERIA ........................................15

3.2.1 Planning Criteria...........................................................................................153.3.2 Operational Criteria......................................................................................183.2.3 Mitigating Unsecured Contingency Events ...................................................21

3.3 DEMAND CONNECTON CRTERA .......................................................................233.3.1 General ..........................................................................................................233.3.2 Planning Criteria...........................................................................................233.3.3 Operational Criteria......................................................................................24

CHAPTER 4: PERFORMANCE CRITERIA AND LIMITS.....................................25

4.1 INTRODUCTION ...................................................................................................254.2 VOLTAGE ............................................................................................................254.3 VOLTAGE PERFORMANCE MARGN .....................................................................28

4.4 FREQUENCY LM

TS ............................................................................................294.5 STABLTY LMTS...............................................................................................29

4.6 FAULT CLEARNG TMES.....................................................................................304.7 SHORT-CIRCUIT LIMITS ......................................................................................304.8 BASC INSULATON LEVEL ..................................................................................314.9 CRTERA FOR EVALUATNG UNSECURED CONTNGENCES ................................324.10 THERMAL LOADNG LMTS OF TRANSMSSON COMPONENTS............................334.11 SUMMARY OF TRANSMISSION SYSTEM REQUIREMENTS NORMAL ANDEMERGENCY CONDITIONS...............................................................................................33


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TRANSMISSION SYSTEM POWER QUALITY STANDARDS..............................36

CONTENTS......................................................................................................................37

CHAPTER 1: INTRODUCTION...................................................................................381.1 POWER QUALITY DEFINITION AND REQUIREMENTS............................................381.2 SCOPE .................................................................................................................40

CHAPTER 2: TRANSMISSION POWER QUALITY STANDARDS.......................41

2.1 VOLTAGE SAG OR VOLTAGE DIP ........................................................................412.2 VOLTAGE STEP CHANGE.....................................................................................422.3 VOLTAGE FLUCTUATONS AND FLCKER.............................................................422.4 HARMONICS ........................................................................................................442.5 PHASE UNBALANCE AND TRACTION LOAD .........................................................462.6 STEP CHANGES OF POWER ..................................................................................49


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GLOSSARY AND DEFINITIONS FOR TRANSMISSION SYSTEM

RELIABILITY STANDARDS AND TRANSMISSION SYSTEM POWER

QUALITY STANDARDS ...............................................................................................50

APPENDIX A BACKGROUND TO THE STANDARDS........................................66

A1PURPOSE ...................................................................................................................67A2STANDARDS FOR BULK GENERATION,TRANSMISSION AND DELIVERY .....................70A3STANDARDS FOR DISTRIBUTION ................................................................................71A4PROCESSES AND PROCEDURES ..................................................................................72A5SUMMARY .................................................................................................................77

APPENDIX B FOR TRANSMISSION SYSTEM RELIABILITY STANDARDS

GUIDANCE ON ECONOMIC JUSTIFICATION OF GENERATION AND

TRANSMISSION CONNECTIONS..............................................................................79

B1GENERAL PRINCIPLES................................................................................................80B2GUDELNES...............................................................................................................80

APPENDIX C FOR TRANSMISSION SYSTEM RELIABILITY STANDARDS

GUIDANCE ON SUBSTATION CONFIGURATIONS AND SWITCHING

ARRANGEMENTS.........................................................................................................82

C1GENERAL GUDANCE.................................................................................................83C2GENERATON PONT OF CONNECTON SUBSTATONS .................................................84C3MARSHALLNG SUBSTATONS....................................................................................84C4GRD SUPPLY PONT SUBSTATONS ...........................................................................84C5(1)TYPICAL TNBSUBSTATION LAYOUT AND SWITCHING ARRANGEMENTS .............86

C5(2)TYPICAL TNBSUBSTATION LAYOUT AND SWITCHING ARRANGEMENTS CONTD........................................................................................................................................87

APPENDIX D FOR TRANSMISSION SYSTEM RELIABILITY STANDARDS

ADDITIONAL CRITERIA TO LIMIT THE COMPLEXITY OF TRANSMISSION

CIRCUITS........................................................................................................................88

D1GENERAL PRINCIPLES ...............................................................................................89D2REQUREMENTS/RESTRCTONS.................................................................................89


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Transmission System Reliability Standards Chapter 1:Introduction

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Chapter 1: Introduction

1.1 General

1.1.1 In large interconnected Electric Power Systems its Reliability is of utmost

importance as electricity is an essential commodity, which underpins the

economic activity of a country. The Transmission Function of an Electric Power

System is pivotal to the objectives of:

a) Developing and maintaining an efficient, coordinated and economical

Transmission System for bulk delivery of electrical energy;b) Ensuring continuous availability of sufficient electrical energy supply for all

consumers, with an adequate margin between supply and demand.

1.1.2 The distinct processes and their related Standards are paramount in ensuring

Reliability in planning the development of an Electric Power System, and in

ensuring its Secure and Robust operation:

1) The Generation Reliability Standard which relates to provision of sufficient

firm Generation Capacity to meet the Demand with a sufficient margin with

allowance for Plant maintenance, Plant breakdown and Plant Unavailability,i.e., scheduled and unscheduled generating Plant outages, to meet the annual

and daily electric energy demand without the need to disconnect customers at

critical periods or cause interruptions in supply. This is used by Tenaga

Nasional Berhad (TNB) to determine additional generation investment

requirements on an annual basis.

2) Transmission Reliability Standard which relates to provision of sufficient

Transmission Capacity, operational facilities, maintenance activity and co-

ordination with generation and Distribution Functions to enable continued

supply of electric energy to the distribution systems and Directly ConnectedCustomers. This Standard is used by TNB to determine the investment

requirements for the Transmission System and transmission operational

facilities and implement the necessary measures.

The development and maintenance of Transmission System Reliability Standards

is the duty of TNB Transmission Division under the provisions of the TNB

Licence that includes Generation Reliability Standards. These Standards are also

termed as License Standards.


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1.1.3 This Standard contains technical terms and phrases specific to Transmission

Systems and the Malaysian Electricity Supply Industry. The meanings of some

terms or phrases in this Standard may also differ from those commonly used

elsewhere. For this reason a Glossary and Definitions has been included as aseparate document but attached to these Standards. All defined terms have been

identified in the text by the use of capitalised words.

1.1.4 Appendix A provides a background the Standards as well as general principles of

its applications.

1.2 Applications and Objectives of the Standards

1.2.1 The electric power Transmission System needs to be planned, operated and

maintained according to a set of Transmission System Reliability Standards. The

development of these Standards determines the investment requirements for

capital Plant and operational facilities; operation and maintenance practices; as

well as provision of Supplementary Services. The provision of levels of

Transmission System performance in accordance with these Standards is the duty

of TNB Transmission Division as specified in TNB License Conditions.

1.2.2 The transmission planning process involves the application of the Transmission

System Reliability Standard and the Transmission System Power Quality Standard

(as the second Standard within this combined document), together with strategic,

environmental and economic analysis, to determine the planned development of

the Transmission System to meet the forecast future demand.

1.2.3 The operational processes involve application of these Standards in operational

planning, maintenance and actual operation of the Electric Power System under

the Prevailing System Conditions on the actual operational day. Whilst the System

operational conditions are carefully planned at the operational planning stage, in

the months, weeks and days ahead, the operation of the System on the day isdictated by the actual prevailing climatic conditions, planned outages as well as

the unplanned events that occur on the day, such as unscheduled generation

breakdown, unplanned transmission outages due to faults and exceptional

demand.

1.2.4 The Standards also provide the limits and permissible excursions of key System

parameters enabling secure implementation of operational measures.


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1.2.5 The above-mentioned transmission Standards therefore determine a defined level

of Reliability for electric power that is delivered at the bulk demand supply points

at the interface between the Main Interconnected Transmission System (MITS)

and the 132kV and 66kV Systems, as well as other parts of the TransmissionSystem and the Distribution Systems at 33kV and below.

1.3 Scope

1.3.1 This document only covers the Transmission System Reliability Standards, which

are the responsibility of TNB Transmission Division. Amendments or changes to

these Standards can only be made with the concurrence of the Energy

Commission (EC) as provided for in the TNB License.

1.3.2 This document is solely concerned with the Standards for the Transmission

System, which includes the Main Interconnected Transmission System (MITS)

and its interface with the Generation Systems as well as the other parts of the

Transmission System which have voltages at 132kV and 66kV. These Standards

are applicable to bulk generation, transmission and delivery of electric power.

These Standards are also reflected in the Malaysian Grid Code which contains all

the technical requirements governing the planning, the development, connection

to, and operation of, the Generation and Transmission System as a whole known

as the Grid System.

1.3.3 Figure 1.1 indicates the contents of the Standards and the subject coverage in

terms of the generation, transmission and distribution Security and Reliability.


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Figure 1.1: The outline contents of the Transmission System Reliability Standards

and its relationship with the systems and codes

G G

Main InterconnectedTransmission System

Transmission radial networkand demand points

Distribution System

Embedded Distribution

Customers

DG

DG

Generation

Transmission

Distribution

GenerationReliabilityStandards

TransmissionReliabilityStandards

TransmissionPower Quality

Standards

Sufficient generation capacityand connections to deliver fullgeneration output for normal

and Specific contingencies

GRIDC

ODE

Sufficient transmissioncapacity to meet demand

for specified contingenciesMeeting standardsperformance limits

Criteria for planning, designingand operating of transmission

system to meet reliability andpower quality standards

Sufficient transformer

capacity to meet demand

Power quality limits atinterfaces

Criteria for planning, designing

and operating of distributionsystem to meet supply security

and power quality standards

STANDARDS CODESDISTRIBUTIONC

ODE

TOTALPOWERSYSTEMS

TransmissionSystem

ReliabilityStandards

Distribution SupplySecurity and PowerQuality Standards


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Transmission System Reliability Standards Chapter 2:Generation Reliability Standard

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Chapter 2: Generation Reliability Standard

2.1 Generation Planning Security Criteria

2.1.1 The Generation Security Standard for the Peninsular Malaysia Electric Power

System shall be the Reliability Index of Loss of Load Probability (LOLP). LOLP

is defined as the proportion of days per 365 days in a year when insufficient

generating capacity is available to serve the daily peak Loads. Alternatively, the

standard can also be defined in term of Loss of Load Expectation (LOLE) which

is a measure of the time duration in a year when insufficient generating capacity is

available to serve the daily peak Loads. Normally, this is expressed in number of

days per year. For the Peninsular Malaysia Grid System the LOLE is normally set

at one (1) day per year, which translates to a LOLP of 0.0274 (ratio of LOLE to

number of days in a year).

2.2 Requirements Associated with Loss of Power Infeed

2.2.1 The Transmission System shall be designed to be secure for the instantaneous

Loss of Power Infeed represented by the output of a single Generating Unit,CCGT Module, imports of power from External Systems or DC Link Monopole

as a result of a Secured Contingency Event. Following such an event the System

Frequency shall return to its Normal Operational Limits defined in the

Transmission System Power Quality Standard within sixty (60) seconds and the

System shall operate within normal voltage and Frequency limits, in a stable

manner both transiently and in the Steady State. There shall be:

(1) no loss of demand;

(2) no overloading of any transmission equipment;

(3) no operation outside post contingency voltage limits; and(4) no excessive degradation of Voltage Performance Margins.

2.2.2 The Largest Loss of Power Infeed Risk for the Peninsular Malaysian Power

System is defined as the largest single generating unit or a CCGT module or a DC

Link Monopole or power import whichever is the largest. In order to ensure the

System is secure after such an event, TNB facilitates the provisions of sufficient

Spinning Reserve and Reactive Power Reserve to avoid deviation of Frequency

and voltage beyond Normal Operational Limits defined in the Transmission

System Power Quality Standard for more than sixty (60) seconds.


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2.2.3 The instantaneous Loss of Power Infeed may exceed that of the Largest Loss of

Power Infeed Risk on very rare occasions which may occur for the loss of a

complete Power Station for contingencies outside the planning or operational

Criteria. This is termed an Infrequent Loss of Power Infeed Risk and is defined asthe loss of the largest single power station. For an Infrequent Loss of Power

Infeed Risk, planning and operational limits may be violated but the Transmission

System shall be planned and operated so that while controlled load loss is allowed,

the integrity of the Transmission System is maintained.

2.3 Generation Connection Criteria

2.3.1 General Generation Connection Requirements

2.3.1.1 This Section of Chapter 2 includes the planning and operational Criteria for the

direct connection of one or more Power Stations to the Transmission System. The

connection Criteria will also apply to the connections from a Demand Supply

Point to the Transmission System by which Power Stations embedded within the

Distribution System or within a Users Network that are connected to the

Transmission System.

2.3.1.2 In planning the Generation Connections, this Standard will be considered as met if

the connection design either:(1) satisfies the minimum deterministic Criteria detailed in paragraphs 2.3.2.1 to

2.3.2.13 below; or

(2) varies from the design necessary to meet item (1) so as to meet a higher

Standard than those set out in paragraphs 2.3.2.1 to 2.3.2.13 below if the

higher Standards can be economically justified or if they are specifically

requested by an external party connecting to the Transmission System, to

ensure a higher level of connection Security and Reliability, which will then

be subject to appropriate commercial negotiation and contract. Guidance on

the economic justification of generation connections is given in Appendix B.

2.3.1.3 The overarching principle in this Standard applicable to the generation

connections is that the transfer capacity of the connection facilities for the

following conditions:

(1) normal System operation;

(2) (n-1) contingencies;

shall provide full export capability for the generation facility into the

Transmission System by satisfying the following Criteria:

(a) the continuous transfer capacity shall be at least equal to the Facility

Contractual Available Capacity (in MW), and


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(b) the connection facilities and the Power Station shall not cause any reduction

in the power quality delivered at the Bulk Supply Points to the Distribution

System and/or to a Users Network.

2.3.2 Planning Criteria for Generation Connections

2.3.2.1 The connection configurations for Generating Units need to be planned to

minimise the effect of coincident Fault Outage(s) of generation and Transmission

Circuits and for the risk of losing multiple Generating Units within a Power

Station.

2.3.2.2 In this respect the Generating Unit connections define the magnitude of the largest

generation loss risk for which dynamic Spinning Reserve will be provided to

contain the Frequency deviation and restore the System Frequency to within limits

defined by the Transmission System Power Quality Standard. Therefore, there is

a requirement to provide sufficient switching facilities and sufficient connection

capability to ensure adequate operational flexibility, and compliance with the

Criteria defined below.

2.3.2.3 Generation connections shall be planned such that starting with an Intact System

the consequences of System contingency events and design of generation

connections to the Transmission System shall be as follows:

(1) following a Fault Outage of any single Transmission Circuit, no Loss of

Power Infeed shall occur;

(2) following the arranged outage of any single section Busbar, the Loss of Power

Infeed shall not exceed the Largest Loss of Power Infeed Risk;

(3) following a Fault Outage of any single Generation Circuit or a single section

of Busbar, the instantaneous Loss of Power Infeed shall not exceed the Largest

Loss of Power Infeed Risk;

(4) following the Fault Outage of any single Transmission Circuit, single section

of Busbar, during the arranged outage of any other single Transmission Circuitor single section of Busbar, the Loss of Power Infeed shall not exceed the

Largest Loss of Power Infeed Risk;

(5) following the Fault Outage of any single Busbar coupler circuit breaker or

Busbar section circuit breaker or mesh circuit breaker, during the arranged

outage of any single section of Busbar or mesh corner, the Loss of Power

Infeed shall not exceed the Largest Loss of Power Infeed Risk.


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2.3.2.4 The connection of a particular Power Station shall meet the following planning

Criteria set out in paragraphs 2.3.2.5 to 2.3.2.8 under the following background

conditions:

(1) the Active Power output of the Power Station and individual Generating Unitsshall be set equal to their respective rated power output, and to the

corresponding full leading or lagging Reactive Power output; and

(2) conditions on the Transmission System shall be set to those which ought

reasonably to be expected to arise in the course of a year of operation. Such

conditions shall include forecast demand cycles, typical Power Station

operating regimes and typical arranged transmission equipment outage

patterns modified where appropriate by the provisions of paragraph 2.3.2.5.

2.3.2.5 The Transmission Capacity for the connection of a Power Station shall be plannedsuch that, for the background conditions described in paragraph 2.3.2.4, prior to

any fault there shall not be any:

(1) equipment loadings exceeding their continuous rating;

(2) voltages outside the Pre-Disturbance Planning Voltage Limits or Insufficient

Voltage Performance Margins; or

(3) System Instability.

The above performance requirements are summarised in Table 4.12, in section

4.11, under system condition classified as Category A No contingencies.

2.3.2.6 The Transmission Capacity for the connection of a Power Station shall also be

planned such that for the background conditions described in paragraph 2.3.2.4

and for the Secured Event of either an Outage of any of the following:

(1) a single Transmission Circuit or element, a reactive compensator or other

Reactive Power resource;

there shall not be any:

a) Loss of Supply Capacity;

b) Unacceptable Overloading of any Primary Transmission Equipment;

c) Unacceptable Voltage Conditions or Insufficient Voltage Performance

Margins; ord) System Instability.

The above performance requirements, contingencies and impacts are summarised

in Table 4.12, in section 4.11, under system condition classified as Category B

Events resulting in loss of a single element.

2.3.2.7 The Transmission Capacity for the connection of a Power Station shall also be

planned such that for the background conditions described in paragraph 2.3.2.4

and for the Secured Event of a Fault Outage of any of the following:


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(1) a Double Circuit Overhead Line (with the exception of 500kV and radial

275kV lines), or

(2) a single Transmission Circuit with the prior outage of another Transmission

Circuit (with the exception of 500kV and radial 275kV lines);(3) a section of Busbar; or

(4) a single Transmission Circuit with the prior outage of a Generating Unit, a

reactive compensator or other Reactive Power resource;

there shall not be:

(a) cascade tripping; and

(b) System Instability.

Under the conditions described above, it is however acceptable for

planned/controlled loss of load to occur. The above performance requirements,

contingencies and impacts are summarised in Table 4.12, in section 4.11, undersystem condition classified as Category C Events resulting in loss of two or

more elements.

2.3.2.8 Under maintenance conditions it shall be assumed that the prior circuit outage(s)

specified in paragraphs 2.3.2.7(1) and 2.3.2.7(4) reasonably form part of the

typical outage pattern referred to in paragraph 2.2.2.4(2) rather than in addition to

that typical outage pattern i.e., only a reasonable typical outage pattern will be

assumed without any double counting or excessive and unrealistic outages being

included.

2.3.2.9 In the event of a contingency more severe than those described in 2.3.2.3, 2.3.2.6

and 2.3.2.7 of this chapter which results in a total generation infeed loss up to the

Infrequent Infeed Loss Risk the Frequency shall not fall below 47.5Hz, with all

defence measures inplace and operational. System performance requirements,

contingencies and expected impacts following more severe or extreme

contingencies than those described in 2.3.2.3, 2.3.2.6 and 2.3.2.7 are summarised

in Table 4.12, in section 4.11, under system condition classified as Category D

Extreme events resulting in two or more elements removed or cascading out of

service.

2.3.2.10 Guidance on typical substation configurations and switching arrangements are

described in Appendix C. However, other configurations and switching

arrangements which meet those Criteria are also acceptable.

2.3.2.11 Variations, arising from a generation customers request, to the generation

connection design necessary to meet the requirements of paragraphs 2.2.1 to 2.2.3

shall also satisfy the requirements of this Standard provided that the varied design

satisfies the conditions set out in paragraph 2.3.2.12(1) to (3). For example, such a


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generation connection design variation may be used to take account of the

particular characteristics of a Power Station.

2.3.2.12 Any generation connection design variation must not, other than in respect ofthe generation customer requesting the variation, either immediately or in the

foreseeable future:

(1) reduce the Security of the Transmission System to below the minimum

planning Criteria specified in Chapter 3; or

(2) result in additional investment or operational costs to any particular customer

or overall, or a reduction in the Security and quality of supply of the affected

customers connections to below the planning Criteria in this chapter or in the

Transmission System Power Quality Standards, unless specific agreements are

reached with affected customers; or(3) compromise TNBs ability to meet other statutory obligations or licence

obligations.

2.3.2.13 Should System conditions subsequently change, for example due to the

proposed connection of a new customer, such that either immediately or in the

foreseeable future, the conditions set out in paragraph 2.3.2.12(1) to (3) are no

longer satisfied, then alternative arrangements and/or agreements must be put in

place such that this Standard continues to be satisfied.

2.3.2.14 The additional operational costs referred to in paragraph 2.3.2.12(2) and/or any

potential Reliability implications shall be calculated by simulating the expected

operation of the Transmission System in accordance with the operational Criteria

set out in Chapters 3 and 4 of this Standard. Guidance on economic justification is

given in Appendix B.

2.3.3 Operational Criteria for Generation Connections

2.3.3.1 The operational Criteria for generation connections are the same as the operationalTransmission System criteria which are set out in Chapter 3 of this Standard.


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Transmission System Reliability Standards Chapter 3:Transmission Reliability Standard

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Chapter 3: Transmission Reliability Standard

3.1 General

3.1.1 The Transmission System is and shall continue to be planned and developed such

that, under both normal System operational conditions or following a Secured

Contingency Event, there will be sufficient Transmission Capacity and capability

available to enable the System to return to normal operation. Normal operation of

the System in this respect means operation of the System within thermal, voltage,

Frequency and stability limits.

3.1.2 In rare circumstances, disturbed System operating conditions involving multiple

outages and/or equipment failures beyond the Secured Contingency conditions

can occur. Usually the occurrence of such events, will result in a controlled or

planned loss of load.

3.1.3 In some rare and extreme cases, Unsecured Contingency Events could also lead to

partial or full disruption of the whole System and affect supplies to consumers.

Under such adverse operating conditions, and as part of the special Protection and

defence measures, some generation and/or demand disconnection is permitted toensure stable operation of the remaining System in the post-contingency period.

3.1.4 This Chapter 3 includes:

(1) the Transmission Adequacy and Security Criteria which ensures adequate

Transmission Capacity so that the Security and integrity of the power System

is maintained for a set of defined Secured Contingency Events;

(2) the planning and operational measures that shall be applied towards mitigating

the impact of rare events with multiple outages and/or equipment failures

beyond the Secured Contingency conditions termed as UnsecuredContingency Events; and

(3) the Demand Connection Criteria which ensures Adequacy of interface

connection capacity to meet demand.

3.1.5 This Chapter 3 also presents the planning and operational Criteria for ensuring

Reliability of the Transmission System. These Criteria apply throughout the

Transmission System and must be met by TNB in planning and operating the

Transmission System. In addition, in those parts of the Transmission System

where the Criteria of Chapter 2 also apply, those Criteria must be met.


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3.2 Transmission Adequacy and Security Criteria

3.2.1 Planning Criteria

3.2.1.1 The following System background conditions will be used to set up the base case

for the planning studies to determine the adequate Transmission Capacity

requirements for the Transmission System:

(1) For the Intact System, the base case power flows shall be set to those arising

from the Planned Transfer Condition prior to application of any fault or

outage;

(2) Conditions on the Transmission System shall be set to those which ought

reasonably to be foreseen to arise in the course of a year of operation. Such

conditions shall include forecast demand cycles, typical Power Station

operating regimes and consideration on arranged transmission equipment

outage. Rearrangement of transmission outages and appropriate reselection

of Generating Units, from those expected to be available may be considered

in order to satisfy the adequate Security Criteria provided that maintenance

access for each Transmission Circuit can be achieved and provided that such

measures are economically justified. Guidance on economic justification is

given in Appendix B;

(3) The expected Availability of generation reactive capability shall be set to thatwhich ought reasonably to be expected to arise. This shall take into account

the variation of reactive capability with the Active Power output as defined

in the machine performance chart. Any long term reactive capability

limitations and exemptions or derogations issued by the Energy Commission

will be taken into account. The target reactive output of generators, at this

stage, shall be set as close as possible to 50% of the expected available

reactive capability;

(4) The Planned Transfer Condition is defined as the condition arising from

scaling the Registered Capacities of each directly connected Power Stationand embedded Large Power Station such that the total of the scaled

capacities is equal to the Peak Demand plus dynamic spinning reserve for

Frequency control and minus imports from External Systems. This scaling

shall be achieved by ranking all directly connected Power Stations and

embedded Large Power Stations in order of likelihood of operation at times

of Peak Demand. Those Power Stations considered least likely to operate at

peak are progressively removed and treated as non-contributory until an

Operational Plant Margin of 10% or just fractionally below is achieved. This

is regarded as sufficient to meet the demand on the day with sufficient Plant

to cater for unscheduled outages and Plant breakdown;


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(5) The output of contributing Power Stations will include its operating reserve

which is calculated in accordance with their ability to provide dynamic

spinning response based on the characteristics of the Plant at that Power

Station;(a) for thermal units, a typical dynamic response of about 8%, if the actual

response is not available;

(b) for GT units, a typical dynamic response of 10%, if the actual response

is not available;

(c) for hydro units, equally proportionally part loaded to balance the

demand, plus losses, plus interconnection infeed;

(d) power imports from External Systems (e.g., Thailand and/or

Singapore) shall be assumed to be at their typical values as indicated

by reciprocal agreements for the base case Planned Transfer Condition;(e) a Load power factor of 0.9 or better shall be maintained, if the

measured power factor is not avilable, at the 132kV side of the

132/33kV and 132/11kV transformers; and

(f) for the Planned Transfer Conditions on the Transmission System there

shall not be:

(i) equipment loadings exceeding the pre-fault rating;

(ii) voltages outside the Pre-fault Planning Voltage Limits or

Insufficient Voltage Performance Margins; or

(iii) system Instability,

otherwise remedial planning measures to remove any violations will be

considered.

3.2.1.2 The minimum Transmission Capacity of the Main Interconnected Transmission

System shall be planned such that, for the background conditions described in

paragraph 3.2.1.1, prior to any fault there shall not be:

(1) equipment loadings exceeding the continuous current rating;

(2) equipment Three-Phase Short-Circuit currents exceeding 90% of their Short-

Time Current Ratings;

(3) voltages outside the Pre-fault Planning Voltage Limits or InsufficientVoltage Performance Margins; or


The above performance requirements are summarised in Table 4.12, in section

4.11, under system condition classified as Category A No contingencies.


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System shall also be planned such that for the background conditions described in

paragraph 3.2.1.1 and for the Secured Contingency Event of a Fault Outage of a

single Transmission Circuit or Element, a reactive compensator or other ReactivePower resource there shall not be any of the following:

(1) Loss of Supply Capacity (except as permitted by the Demand Connection

Criteria detailed later in this Chapter 3);

(2) Unacceptable Overloading of any Primary Transmission Equipment;

(3) Unacceptable Voltage Conditions or Insufficient Voltage Performance

Margins; or



in Table 4.12, in section 4.11, under system condition classified as Category B Events resulting in loss of a single element.


System shall also be planned such that for the background conditions described in

paragraph 3.2.1.1 and for the Contingency Event of a Fault Outage of any of the

following:


275kV lines), or


Circuit (with the exception of 500kV and radial 275kV lines);

(3) a section of Busbar or mesh corner; or

(4) any single Transmission Circuit with the prior outage of another Transmission

Circuit, Generating Unit, reactive compensator or other Reactive Power

resource,

there shall not be:




planned/controlled loss of load to occur. The above performance requirements,contingencies and impacts are summarised in Table 4.12, in section 4.11, under

system condition classified as Category C Events resulting in loss of two or

more elements.

3.2.1.5 In addition to the requirements set out in paragraphs 3.2.1.3 and 3.2.1.4, for the

background conditions described in paragraph 3.2.1.1, the System shall also be

planned such that operational switching of any component or part of the Main

Interconnected Transmission System shall not cause:



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18

(2) Unacceptable Voltage Conditions or Insufficient Voltage Performance

Margins;

(3) Any switchgear with duty exceeding 90% of its Short Circuit Break or Make

capacity;or(4) System Instability.

3.2.1.6 Circuits comprising the Main Interconnected Transmission System shall not

exceed the circuit complexity limit defined in Appendix D.

3.2.1.7 Guidance on substation configurations and switching arrangements are described

in Appendix C. These guidelines provide an acceptable way towards meeting the

Criteria of this Chapter 3. However, other configurations and switching

arrangements which meet the Criteria are also acceptable.

3.2.2 Operational Criteria

3.2.2.1 The Main Interconnected Transmission System shall be operated under Prevailing

System Conditions so that for the Secured Contingency Event of a Fault Outage of

a single Transmission Circuit or Element, a reactive compensator or other

Reactive Power provider there shall not be any of the following:

(1) a Loss of Supply Capacity (except that under certain maintenance outage

conditions, should an unplanned outage occur, some loss of Load can be

accepted, and except as permitted in paragraph 3.2.2.3);

(2) Unacceptably High or Low Frequency Conditions;


(4) Unacceptable Voltage Conditions; or



in Table 4.12, in section 4.11, under system condition classified as Category B

Events resulting in loss of a single element.

3.2.2.2 The Main Interconnected Transmission System shall be operated under Prevailing

System Conditions so that for Contingency Event of any of the following:


275kV lines); or


Circuit (with the exception of 500kV and radial 275kV lines); or

(3) a section of Busbar or mesh corner; or


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19

(4) any single Transmission Circuit with the prior outage of another

Transmission Circuit, Generating Unit, reactive compensator or other

Reactive Power resource, or

(5) the most onerous Loss of Power Infeedthere shall not be:




planned/controlled loss of load to occur. The above performance requirements,

contingencies and impacts are summarised in Table 4.12, in section 4.11, under

system condition classified as Category C Events resulting in loss of two or

more elements.

3.2.2.3 The operational Criteria above are subject to the following exceptions:

(1) Provided that it is in accordance with the appropriate requirements of the

demand connections criteria in part 3.3 of this Chapter 3, there may be an

associated Loss of Supply Capacity due to a Secured Contingency Event, for

example by virtue of the design of the generation connections and/or the

designed switching arrangements at the substations concerned. Typical

examples of this could be:

(a) at mesh substations where the loss of a Double Circuit Overhead Line

would result in the consequential loss of mesh corner Demand Supply

Point transformers;

(b) Demand Supply Point transformers which are teed off circuits that form

part of the Main Interconnected Transmission System and which would

become disconnected following the loss of these circuits.

(2) During periods of Severe Weather conditions or other high System risk

periods, TNB Transmission Division may implement measures to mitigate the

consequences of this risk. Such measures may include reducing output at

certain Power Stations.

3.2.2.4 For the purposes of paragraph 3.2.2.2, it is acceptable to utilise short term postfault actions to avoid Unacceptable Overloading of Primary Transmission

Equipment which may include a requirement for demand reduction; however this

will not be used as a method of increasing reserve to cover abnormal post fault

generation reduction. Where possible these post fault actions shall be notified to

the appropriate Users. Normally the provisions of the Grid Code, in respect of

Emergency Manual Demand Disconnection will be applied. Additional post fault

actions beyond the Grid Code provisions may be applied, but only where they

have been agreed in advance with the appropriate Users.


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20

3.2.2.5 Post-fault Restoration of System Security - Following the occurrence of a Secured

Contingency Event measures shall be taken to re-secure the System to the above

operational Criteria as soon as reasonably practicable. To this end it is permissible

to put operational measures in place to facilitate the speedy restoration of SystemSecurity.

3.2.2.6 Authorised Variations From the Operational Criteria - The principles of these

operational Criteria shall be applied at all times except in special circumstances

where TNB, following consultation with the appropriate Network Operator,

Generator or Directly Connected Customer, may need to give instructions to the

contrary to preserve overall System integrity.


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21

3.2.3 Mitigating Unsecured Contingency Events

3.2.3.1 In rare circumstances, disturbed System operating conditions, with multipleoutages and/or equipment failures beyond the Secured Contingency conditions

can occur on the Transmission System. Such events can lead to partial or full

disruption of the whole System and affect the Security and Adequacy of supplies

to consumers. Reasonably predicting the full extent and nature of such events

and hence putting sufficient investment in preventive measures is not fully

possible even when excessively large capital investment is available. These types

of events are therefore termed as Unsecured Contingency Events.

3.2.3.2 In practice however, TNB Transmission Division shall evaluate and install

special protective measures and defence mechanisms such that the impact of the

Unsecured Contingency Events is contained such that only part of the System

may be affected with some generation and demand loss.

3.2.3.3 The Transmission System is and shall continue to be planned and developed

such that special protective measures and defence mechanisms are included not

only to prevent a total System shutdown but also to facilitate rapid recovery to

normal System operation in the case of Unsecured Contingency Events. Under

such adverse operating conditions and as part of the special Protection and

defence measures loss of some generation and/or demand is permitted to ensure

stable operation of the remaining System in the post-contingency period.

3.2.3.4 Planning Requirements - As part of the System planning process, based upon the

System background conditions in paragraph 3.2.1.1 (used to set up the base case

for the planning studies to determine the adequate Transmission Capacity

requirements for the Transmission System), TNB shall study the impact of and

the sensitivity of the System to Unsecured Contingency Events relating to

multiple and very severe but rare System contingency events well beyond the

Secured Contingency Events.

3.2.3.5 For the impact assessment at the System planning stage the following types of

Unsecured Contingency Events will be considered and fully evaluated.

Consideration and full evaluation of events will not be restricted to those events

listed below but an assessment of reported events occurring in other power

Systems and a full consideration of such events as relevant to the Transmission

System. The types of Unsecured Contingency Events include:

(1) Loss of a bus section;

(2) Stuck breaker;


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22

(3) Loss of the transmission towers in a Right of Way (involving loss of two or

more double circuit lines);

(4) Loss of a substation; and

(5) Loss of a complete Power Station.In making the assessment, system performance requirements, contingencies and

expected impacts following Unsecured Contingency Events or extreme

contingencies summarised in Table 4.12, in section 4.11, under system condition

classified as Category D - Extreme events resulting in two or more elements

removed or cascading out of service - shall be considered.

3.2.3.6 Operational Requirements - The Main Interconnected Transmission System shall

be operated with all the special Protection and defence measures in a fully

operational state. If any one or more of these measures are out of service or onmaintenance then specific Operational Planning studies shall be carried out well

in advance to put in place appropriate operating regimes and alternative

measures with a target of reducing the risk.


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3.3 Demand Connection Criteria

3.3.1 General

3.3.1.1 The Demand Connection Criteria relate to the planning of demand connections

and provision of sufficient transformer capacity and/or demand transfer facilities

to avoid undue Loss of Supply Capacity for Secured Contingency Outages

included in the Transmission Reliability Standard. These Criteria enable TNB

Transmission Division and the Distributors, Network Operators or Directly

Connected Customers to make necessary investments ensuring the planning,

development and operation of the Transmission and Distribution Systems within

the provisions of Transmission System Reliability and Power Quality Standards,

and the Grid Code both under normal and Secured Contingency Outage

conditions.

3.3.1.2 This section of Chapter 3 presents the planning and operational Criteria for the

connection of demand to the Transmission System. In those parts of the

Transmission System where the Criteria of Chapter 2 of this Standard also apply,

those Criteria must also be met.

3.3.2 Planning Criteria

3.3.2.1 The objective of planning is to ensure there are sufficient connections from the

Transmission System at the Demand Supply Point such that the demand can be

fully met under secured contingency conditions.

3.3.2.2 The supply of demand shall also be planned such that for the background

conditions described in paragraph 3.2.1.1 and for the Secured Contingency Event

of a Fault Outage of a single Transmission Circuit, a reactive compensator or

other Reactive Power resource, or a step down transformer supplying demandwhose high voltage side is connected to the Transmission System, there shall not

be any loss of demand. The performance requirements, contingencies and impacts

for the demand connection are summarised in Table 4.12, in section 4.11, under

system condition classified as Category B Events resulting in loss of a single

element.

3.3.2.3 The above requirements shall not preclude the Customer/demand to be provided

with higher or lower security of supply level as stated in appropriate Agreement.


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3.3.2.4 It is permissable to secure demand against the contingencies outlined in section

3.3.2.2 by demand transfer or other methods at distribution voltages levels.

3.3.3 Operational Criteria

3.3.3.1 In the case of a planned outage of a single Transmission Circuit, a reactive

compensator or other Reactive Power resource, or a step down transformer

supplying demand whose high voltage side is connected to the Transmission

System, full demand may not be met for a subsequent forced outage.


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Transmission System Reliability Standards Chapter 4:Performance Criteria and Limits

25

Chapter 4: Performance Criteria and Limits

4.1 Introduction

4.1.1 This Chapter 4 presents performance criteria and limits used in this Standard for

planning and operation. performance criteria and limits specified in this Chapter

are:

(1) Voltage;

(2) Voltage Performance Margin;

(3) Frequency Limits;

(4) Stability Limits;

(5) Fault Clearing Times;

(6) Short Circuit Limits;

(7) Basic Insulation Levels;

(8) Criteria for Evaluating Unsecured Contingencies; and

(9) Thermal Loading Limits of Transmission Components.

4.1.2 The specified criteria and limits in this Chapter shall be complied with for

planning and operation of the Grid as outlined in Chapter 2 and Chapter 3.

4.2 Voltage

4.2.1 The Transmission System is planned, maintained and operated in accordance with

the Standards included in Chapters 2 and 3. Pre-Fault Planning Voltage Limits

and Unacceptable Voltage Conditions are defined as follows. The operation of the

System is planned in Operational Planning timescales for operation within the

Pre-Fault Planning Voltage Limits and operated under the Prevailing System

Conditions so that for the Secured Contingency Event of a Fault Outage, any

Unacceptable Voltage Conditions will not be experienced. Under rare Unsecured

Contingency Events some parts of the System may experience Unacceptable

Voltage Conditions and some parts of the voltage may experience total loss of the

supply voltage.


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4.2.2 The voltage limits applicable in planning studies for the pre-disturbance/pre-fault

state of the Transmission System are (see table 4.1):

Table 4.1: Pre-disturbance voltage limits for planning studiesNominal Voltages Maximum Minimum (Note 2)

500kV 525kV (+5%) 500kV (-0.0%)

275kV 289kV (+5%) 275kV (-0.0%)

132kV 139kV (+5%) 132kV (-0.0%) (Note 1)

Lower Voltages 1.05 p.u. (+5%) 1.0 p.u. (-0.0%) (Note 1)Note 1 There is no minimum planning voltage provided that, at the Busbar of the same nominal voltage atthe Demand Supply Point from which it is derived, it is possible (for example by tap changing) to achieve atleast 105% of nominal voltage.Note 2 It is assumed that at the planning stage the load power factor at the 132kV bus is no lower than 0.9 .

4.2.3 In both planning and operational timescales the voltage is unacceptable if outsidethe limits set out in table 4.2.

Table 4.2: Unacceptable voltage limits in planning and operation

Planning Timescales

Note 1Operational TimescalesNominal

VoltageMaximum Minimum Maximum Minimum

500kV

525kV (+5.0%)

Note 2

475kV (-5.0%)

Note 3

525kV (+5.0%)

Note 6

450kV (-10.0%)

275kV 289kV (+5.0%) 248kV (-10.0%) 303kV (+10.0%) 248kV (-10.0%)

132kV 139kV (+5.0%) 145kV (+10%) 119kV (-10%)

Less than

132kV(+5.0%) Note 4

Note 5

(+6.0%) (-6.0%)

Note1 These voltages to be achieved without widespread post-fault generation transformer re-tapping or

postfault adjustment of reactive compensation equipment reference voltage set points to increase the

Reactive Power output or to avoid exceeding the available reactive capability of generation or

reactive compensation equipment.

Note 2 It is permissible to relax this to 550kV (+10%) if lasting for no longer than 15 minutes (or longer if

the equipment permits).

Note 3 It is permissible to relax this to 450kV (-10%) if:

the affected substations are on the same radially fed spur post-fault;

there is no lower voltage interconnection from these substations to other Main

Interconnected System Substations; and

no auxiliaries of Large Power Stations are derived from them.

Note 4 It shall be possible to operate the lower voltage Busbar of a Demand Supply Point up to 100% of

nominal voltage unless the Secured Contingency Event includes the simultaneous loss of a

500/275kV transformer.

Note 5 The target operational voltages at Demand Supply Point should be as agreed with relevant

Users.

Note 6 It is permissible to relax this to 550kV (+10%) if lasting for no longer than 15 minutes (or longer if

the equipment permits).


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4.2.4 Under System operational conditions elements of the Transmission System need

to be switched to optimise the operation of the System, to facilitate maintenance

and to isolate faulty equipment for repair. Under such operational activities

switching of any element or equipment shall not cause unacceptable Voltage StepChanges. The voltage change is deemed unacceptable if it changes by more than

the limits set out in table 4.3.

Table 4.3: Unacceptable voltage step changes in planning and operation

Planning Timescales

Note 1

Operational Timescales

Note 3

System Condition

Voltage

Rise

Voltage Fall Voltage

Rise

Voltage Fall

Following SecuredContingency Events

+10%

-2.5% for500kV

-5% for

others

Note 2

+10%

-2.5% for500kV

-5% for

others

Note 4

Following operational

switching less frequent

than specified in ER P28

+3% -3% +3% -3%

Otherwise According to ER P28Note 1 These limits apply at all demand conditions and only to the interfaces between the

Transmission System and customers, and must be applied with the Load response tovoltage change taken into account.

Note 2 This is relaxed to -12% if the fault involves the loss of a section of Busbar, or a meshcorner, or a Secured Contingency Event which also includes the simultaneous loss of a500/275kV transformer (Applicable to voltage other than 500kV).

Note 3 Following Voltage Step Change within these limits, it must be possible to restore theSteady State voltage to 95% of nominal at Demand Supply Points following any manualand/or automatic facilities available, including switching in or out of relevant Apparatus.

Note 4 This is relaxed to -12% if the fault involves the loss of a Double Circuit Overhead Line, asection of Busbar, or mesh corner(Applicable to voltage other than 500kV).


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4.2.5 Limits of voltage changes due to frequent and infrequent operational switching of

Load both by TNB and the User are defined as follows (see table 4.4), provided

that this does not constitute a risk to the Transmission System.

Table 4.4: Voltage limits on switching of load

Load Switching Limit of Voltage Change

Infrequent single switching ordisconnection of Load (e.g., twice a day)Including capacitor banks and reactors

3%

Frequent switching and/or disconnectionof Load (e.g., Many times in a day)

1%

4.2.6 Immediately following a fault clearance and removal of the faulted item of

equipment from the Transmission System, and, prior to reaching Steady Stateconditions whose limits are described in Sections 4.2.3 and 4.2.4 above, the

voltage at any point on the Main Interconnected Transmission System is

unacceptable if outside the limits set out in the table 4.5.

Table 4.5: Dynamic voltage excursion limits

Low voltage High voltage

0.7 p.u. for not more than 400ms 1.2 p.u. for not more than 30s

4.3 Voltage Performance Margin

4.3.1 At the planning stage power transfer within the System and at each specific

demand point shall be limited such that there is a margin of 15% to the maximum

possible transmitted power, under the base case conditions described in Section

3.2.1.1 of this Standard.

4.3.2 At the planning stage power transfer within the System and at each specific

demand point shall be limited such that there is a margin of 7.5% to the maximum

possible transmitted power, under the contingency conditions described in Section

3.2.1.4of this Standard.

4.3.3 During operation, power transfer within the System and at each specific demand

point shall be limited such that there is a margin of 5% to the maximum possible

transmitted power, under the contingency conditions described in Section 3.2.2.1

of this Standard.

4.3.4 These voltage margin Criteria are in additon to any other voltage Criteria

requirements.


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4.4 Frequency Limits

4.4.1 During normal steady-state operational conditions the Frequency is to be

maintained to within 1% of the nominal, that is, between 49.5 and 50.5Hz.

4.4.2 The System Frequency could rise to 52Hz or fall to 47Hz in extremely rare and

exceptional circumstances. Therefore the design of both TNB and User's Plant and

Apparatus must enable operation of that Plant and Apparatus within that range in

accordance with table 4.6.

Table 4.6: Frequency excursion limits

Frequency Range Requirement

47.5Hz - 52Hz*

Continuous operation is required47Hz - 47.5Hz Operation for a period of at least 10 seconds is required

each time the Frequency is below 47.5Hz* This value may be lowered to 51.5Hz if substantive evidence can be provided to show

that the operation of the generating unit beyond 51.5Hz will affect the safety of the plant.

4.5 Stability Limits

4.5.1 The relative rotor angle of any two Generating Units in the System must not

exceed 180 degrees at any time.

4.5.2 Following any disturbance the Damping Ratio of power, angle or voltage

oscillation must not be less than 5%.


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4.6 Fault Clearing Times

4.6.1 The following maximum fault clearance times (see table 4.7) are normallyexpected from the Main Protection equipment installed in the Transmission

System.

Table 4.7: Maximum Fault Clearing Times

System Voltage (kV) Fault Location Fault Clearance Time (ms)

Substation 100500 and 275

Overhead Line/Cable 100

Substation 150132

Overhead Line/Cable 150

4.6.2 For planning studies:

(1) a 100ms fault clearance time shall be used for system at nominal voltage of

500kV and 275kV;

(2) a 150ms fault clearance time shall be used for system at nominal voltage of

132kV.

Fault clearance time is defined as the time between fault inception and complete

disconnection of the faulted item of equipment from the Transmission System.

4.6.3 For operational studies the Protection times in 4.6.2 shall also be used. However,

where the used of fault clearing times in 4.6.2 is found to be limited, the actual

fault clearing times may be used.

4.7 Short-Circuit Limits

4.7.1 The Transmission System shall be planned such that the maximum sub-transient

three phase symmetrical short circuit fault levels are not greater than 90% of theswitching equipment short-circuit ratings, the breaking and making capacities of

switching equipment shall not be exceeded under maximum system short circuit

condition.

4.7.2 For three-phase or single-phase-to-earth faults, the planned maximum sub-

transient short circuit fault levels shall not be greater than that indicated in the

table 4.8.


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Table 4.8: Short-circuit limits

System Voltage (kV) Circuit Breaker

Short Circuit Rating Break Capacity

500 50kA, 1s

275

x 40kA, 3s for bulk substation

x 50kA, 1s for Power Station and 275kV within 500kV

substation

132 x 31.5kA, 3s

x 40kA, 3s for Power Station and 132kV within a

500/275kV substation

33 25kA, 3s

22, 11, 6.6 20kA, 3s

0.415 and 0.240 31.5kA, 3sNote: Typically closing-and-latching (momentary) capability of a circuit breaker as anrms current is not more than 1.6K times Symmetrical Short Circuit Rating or as aninstantaneous peak current is not more than 2.7K times Symmetrical Short Circuit Rating.For most circuit breakers, K is equal to one.

4.8 Basic Insulation Level

4.8.1 Typical Basic Impulse Insulation Levels (BIL) of the Transmission andDistribution Systems are as given in the following table. The Users Plant and

Apparatus is required to match these insulation levels. These may vary under

specific circumstances.

Table 4.9: Basic insulation level (BIL)

System Voltage (kV) BIL (kV)

500 1550

275 1050

132 65033 170

22 125

11 and 6.6 75


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4.9 Criteria for Evaluating Unsecured Contingencies

4.9.1 For the purposes of determining the types of special Protection and defencemeasures the following contingencies which will be considered together with the

appropriate Fault Outage Criteria to be considered are listed in table 4.10 and also

as described under Category D of Table 4.12, in section 4.11,. In all these cases

special Protection and/or defence measures shall be put in place such that whilst

some demand and generation loss may be experienced a total System shutdown

will be avoided.

Table 4.10: Unsecured contingencies to be evaluated

Unsecured

Contingency

Event

Fault Outage CriteriaNote 1

Outage of System

Elements

Bus Section Fault Single-phase-to-ground fault cleared in

250 ms followed by the loss of the

entire bus section through tripping of

all circuit breakers connected to that

section of Busbar

All Transmission Circuits

and any transformers and/or

reactive compensation

equipment connected

Stuck Breaker

Fault Single Phase

Fault Initiation

Single-phase-to-ground fault being

cleared in 250 ms by the tripping of the

circuit breakers of transmissionelements in the immediate proximity to

clear the fault which could not be

normally cleared due to the stuck

breaker


and any transformers and/or

reactive compensationequipment in the immediate

proximity

Stuck Breaker

Fault Three Phase

Fault Initiation

Three-phase fault cleared in normal

clearing time followed by a single line

to ground fault cleared in delayed time.

Typical delay time is assumed at

250ms.


and any transformer and/or

reactive compensation

equipment in the immediate

proximity

Loss of one Bipole of

the HVDC

Interconnector

Blocking of one Bipole through its

control equipment reducing the current

flow to zero and the resumption of

current flow

Outage of some elements of

the HVDC link

Loss of Right of Way Three-phase fault cleared in 150ms or

100ms followed by the loss of circuits

on the Right of Way

Loss of all circuits on the

Right of Way


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Unsecured

Contingency

Event

Fault Outage CriteriaNote 1

Outage of System

Elements

Loss of substation

(one transmission

voltage level plus

associated

transformers) i.e., loss

of a Busbar

Three-phase fault cleared in 150ms or

100ms followed by the loss of circuits

connected to the busbar

Loss of all circuits

connected to the busbar

Loss of a complete

Power Station

Three-phase fault cleared in 150ms or

100ms followed by the loss of all

Generating Units at the Power Station

Loss of all Generating Units

at the Power Station

Note 1: Normal clearing time - Three-phase fault duration for 500kV and 275kV is 100ms and forand 132kV is 150ms

4.10 Thermal Loading Limits of Transmission Components

4.10.1 The thermal loading limits of equipment in planning and operational timescales

are defined in table 4.11.

Table 4.11: Thermal loading limits on transmission components

Equipment Planning Operation

Lines No thermal overloading

allowed

130% for not more than thirty

(30) minutes or an applicabletime dependent emergency limit

Underground cables Strict observation of

equipment continuous rating


(30) minutes or an applicable

time dependent emergency limit

Transformers No thermal overloading

allowed


(30) minutes or an applicable

time dependent emergency limit

Switching and

Isolation Equipment

Strict observation of

equipment continuous rating

Applicable time dependent

emergency limit

4.11 Summary of Transmission System Requirements Normaland Emergency Conditions

4.11.1 Table 4.12 summarises the required and/or expected performance of thetransmission system under four (4) categories of contingencies and for eachcategory:(1) the initiating events and contingency elements; and(2) system performance requirements and expected impactsare specified.


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Table 4.12: Summary of System Performance Requirements Following Events

Involving Loss of Single or More Grid System Elements under Both Normal and

Emergency ConditionsContingencies System Limits or Impacts

CategoryInitiating Event(s) and

Contingency Element(s)System Stable

& both Thermal

and Voltage

Limits within

Applicable

RatingNote (a)

Loss ofDemand

or

Curtailed

Firm

Transfers

CascadingOutages

ANoContingencies

All Facilities in Service Yes No No

Single Line Ground (SLG) or 3-Phase (3) Fault with NormalClearing (Note (e)):1. Generator2. Transmission Circuit

3. TransformerLoss of an Element without aFault

YesYes

YesYes

NoNo

NoNo

Note (b)

NoNo

NoNo

BEvent resultingin the loss of asingle element

Single Pole Block, NormalClearing (Note (e)):4. Single Pole (dc) Line Yes No

Note (b)No

SLG Fault, with Normal Clearing(Note (e)):1. Bus Section

2. Breaker (failure or internalfault)

Yes

Yes

Planned/ControlledPlanned/

ControlledNote (c)

No

No

SLG or 3 Fault, with NormalClearing (Note (e)). ManualSystem Adjustment, followed byanother SLG or 3 Fault, withNormal Clearing (Note (e)):3. Category B (B1, B2, B3 or

B4) contingency, manualsystem adjustments, followedby another Category B(B1,B2, B3 or B4) contingency

Yes Planned/ControlledNote (c)

No

Bipolar Block with NormalClearing (Note (e)):4. Bipolar (dc) Line Fault (non

3) with Normal Clearing

(Note (e))5. Any two circuits of a multiple

circuit tower (Note (f)).

Yes

Yes

Planned/Controlled

Planned/ControlledNote (c)

No

No

CEvent(s)resulting in theloss of two ormore (multiple)elements

SLG Fault, with DelayedClearing (stuck breaker orprotection system failure) (Note(e)):6. Generator

7. Transformer

8. Transmission Circuit

9. Bus Section

Yes

Yes

Yes

Yes

Note (c)

Planned/ControlledPlanned/

ControlledPlanned/

Controlled

Planned/Controlled

No

No

No

No


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Contingencies System Limits or Impacts

CategoryInitiating Event(s) and

Contingency Element(s)

System Stable

& both Thermal

and Voltage

Limits within

ApplicableRatingNote (a)

Loss of

Demand

or

Curtailed

FirmTransfers

Cascading

Outages

DExtreme eventresulting in twoor more(multiple)elementsremoved orCascading outof service

Note (d)

3 Fault with Delayed Clearing (stuck breaker or protection systemfailure) (Note (e)):

1. Generator2. Transmission (Circuit)3. Transformer4. Bus Section

3 Fault with Normal Clearing (Note (e)) :5. Breaker (failure or internal Fault)6. Loss of tower with three or more circuits

7. Loss of all transmission lines on a common right-of way8. Loss of a substation (one voltage level plus transformers)9. Loss of a switching station (one voltage level plus transformers)10. Loss of all generating units at a station.11. Loss of large Load or major Load center12. Failure of a fully redundant Special Protection System to operate

when required13. Operation, partial operation, or misoperation of a fully redundant

Special Protection System in response to an event or abnormalsystem condition for which it was not intended to operate

14. Impact of severe power swings or oscillation from Disturbancesin another Interconnected Systems

Elevate for risks andconsequences:

x May involvesubstantial loss ofcustomer Demandand generation ina widespread areaor areas

x Portions or all oftheinterconnection

systems may ormay not achieve anew, stableoperating point.

x Evaluation ofthese events mayrequire jointstudies withneighboringsystems.

Notes:(a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating (see table4.11) or system voltage limit as determined and consistently applied specified in section 4.1 of thisStandard. Applicable Ratings may include Emergency Ratings applicable for short durations asrequired to permit operating steps necessary to maintain system control.

(b) Planned or controlled interruption of electric supply to radial customers or some local Networkcustomers connected to or supplied by the Faulted element or by the affected area, may occur in certainareas without impacting the overall reliability of the interconnected transmission systems. To preparefor the next contingency, system adjustments are permitted, including curtailments of contracted firmpower transfers.

(c) Depending on system design and expected system impacts, the controlled interruption of electricsupply to customers (load shedding), the planned removal from service of certain generation, and/or thecurtailment of contracted firm power transfers maybe necessary to maintain the overall reliability of the

interconnected transmission systems.(d) A number of extreme contingencies that are listed under Category D and judged to be critical will be

selected for evaluation. It is not expected that all possible facility outages under each listed contingencyof Category D will be evaluated.

(e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the timenormally expected with proper functioning of the installed protection systems (see table 4.7). Delayedclearing of a Fault is due to failure of any protection system component such as a relay, circuit breaker,or current transformer, and not because of an intentional design delay. Three phase delayed clearing iswhen a three phase fault is cleared in normal clearing time followed by a SLG fault cleared after adelay time (to represent the single pole of a stuck breaker or protection system failure). Typical delaytimes are 250 milliseconds

(f) System assessment may exclude these events where multiple circuit lowers are used over shortdistances (e.g. substation entrance, river crossings).


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Transmission System Power Quality Standards Contents

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Transmission System Power

Quality Standards

Effective January 1, 2006

Version 2.0Edition 1.0

TENAGA NASIONAL BERHAD, 2006


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Contents

TRANSMISSION SYSTEM POWER QUALITY STANDARDS..............................36

CONTENTS......................................................................................................................37

CHAPTER 1: INTRODUCTION...................................................................................38

1.1 POWER QUALITY DEFINITION AND REQUIREMENTS............................................381.2 SCOPE .................................................................................................................40

CHAPTER 2: TRANSMISSION POWER QUALITY STANDARDS.......................41

2.1 VOLTAGE SAG OR VOLTAGE DIP ........................................................................412.2 VOLTAGE STEP CHANGE.....................................................................................42

2.3 VOLTAGE FLUCTUATONS AND FLCKER.............................................................422.4 HARMONICS ........................................................................................................442.5 PHASE UNBALANCE AND TRACTION LOAD .........................................................462.6 STEP CHANGES OF POWER ..................................................................................49


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Chapter 1: Introduction

1.1 Power Quality Definition and Requirements

1.1.1 In this Standard, Power Quality is defined as the degree to which the Voltage at

the point of connection to the User of the Transmission System is maintained to be

Sinusoidal at declared rated Voltage and Frequency within the stipulated limits.

1.1.2 Major Power Quality Problems that are associated with the Transmission System

is Voltage Sag or Voltage Dip. Voltage sag would occur in the System during the

short-circuit fault. The most severe Voltage Sag would occur at the fault location

and the Voltage Sag effects would be propagated throughout the Systems with the

magnitude of the Voltage Dip attenuated.

1.1.3 Voltage Sag could also be caused by short circuit faults in Users System and

propagated to other Users Systems through the Transmission Systems or through

the Distribution System as the case may be. Majority of problems associated with

harmonics are caused by non-linear loads that draw non-sinusoidal current from

the system and thus causing the supply voltage to be distorted. Frequent switching

of large load such as motors is also another source of power quality problems thatresult in voltage flicker to be experienced by other Users.

1.1.4 The approaches to resolving power quality problems depend on the types of the

power quality problems. Both utility and Customers have their individual roles

and responsibilities in resolving power quality problems. Individual Customer

shall ensure that any non-linear load to be connected to the Transmission System

does not produce harmonic currents that would result in voltage at Point of

Common Coupling to be distorted beyond the limits as set out in section 2.4 of

this Standard. Likewise the utility shall continue to monitor and ensure thatHarmonic limits as specified in section 2.4 are complied with.

1.1.5 Voltage sag could affect sensitive loads usually connected at low voltage network

of the Customers installation. Not withstanding the presence of several voltage

transformations from transmission voltage to low voltage, voltage sag caused by

Transmission faults can affect Customers voltage sensitive loads and the effect is

more pronounced during severe three-phase faults on the Transmission System. It

shall be the responsibility of the utility to provide appropriate information on

voltage sag and for the individual customer to ensure sufficient ride-through

capability of the voltage sensitive equipment.


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1.1.6 The Standards contained in this document specify the Power Quality requirements

of the bulk supply point that delivers electricity supply to the Distribution System

and other bulk supply Users in terms of stable voltage and frequency within

specific limits so that Generator, TNB Transmission equipment or Consumersequipment directly connected to the Transmission System can operate safely

within its design performance without suffering undue damage or breakdown.

1.1.7 The requirements and limits specified in this Standard shall also be complied with

by all Users connected or intending to be connected to the Transmission System.

1.1.8 Consequently these Standards also determine the investment required in provision

and/or procurement of Supplementary Services such as Reactive Power, Active

Power response, hot standby generation, fast start generation, demand control andblack start by TNB Transmission. They also indicate the investment required both

in the Transmission and Distribution Systems for containing harmonics, voltage

unbalance as well as the permitted types and levels of special Loads adversely

affecting the power quality and requirements for compensation plant to limit their

adverse effects. Compliance with these Standards is the responsibility of TNB

Transmission, Generators, Distributors, Network Operators and Non-Embedded

Customers.

1.1.9 In order to achieve the required Transmission Power Quality these Standards will

be used by TNB Transmission in planning, developing, maintaining and operating

the Transmission System as well as in connecting generation and demand to the

System. In turn the equipment utilised by the Generators, TNB Transmission,

Distributors and Customers also need to comply with the provisions of this

Standard. Compliance with these Standards is therefore not optional and where a

connecting partys plant or equipment is likely to be non-compliant at the

planning stage then such plant and/or equipment will not be energised until

appropriate remedial measures are put in place and are fully functional. In

addition, TNB Transmission shall put in place appropriate monitoring facilities to

ensure compliance with the provisions of this Standard as part of its Licence.

1.1.10 In cases where, the nature and operation of the new types of plant and equipment

to be connected to the Transmission System is perceived to be likely to cause

problems to other customers and users of the System, but not fully covered by

this Standard, appropriate remedial measures shall be put in place based on expert

advice within a mutually agreed time period.


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1.2 Scope

1.2.1 This Standard covers most of the power quality related phenomena generated byvarious types of plant and equipment connected to the Transmission System. In

each particular case the Transmission Power Quality that should be maintained is

indicated together with the remedial approach and responsibilities of parties.


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Chapter 2: Transmission Power Quality Standards

2.1 Voltage Sag or Voltage Dip

2.1.1 Voltage sag, dip or swell is the transient phenomena which can affect the

voltage level and is usually experienced during System faults and the subsequent

recovery period. These phenomena can adversely affect some customer equipment

that are sensitive to such changes. This Standard does not specifically cover

voltage sag, dip or swell.

2.1.2 The voltage sags are caused by faults on the Transmission System due to short

circuits incidents which are cleared by System Protection. The nature and

technical detail of such events is a function of the location of the connection point

on the System, the distance of the short circuit from the connection point and the

short-circuit level at the connection point, the severity (magnitude and duration) of

the short circuit. Voltage Sag may also

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