Malaysia Transmission System Reliability Standards

Transmission System Reliability Standards

Effective January 1, 2006

Version 2.0 Edition 1.0

TENAGA NASIONAL BERHAD, 2006

Transmission System Reliability Standards Contents

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Contents

TRANSMISSION SYSTEM RELIABILITY STANDARDS ........................................1 CONTENTS........................................................................................................................1 CHAPTER 1: INTRODUCTION.....................................................................................4

1.1 GENERAL ..............................................................................................................4 1.2 APPLICATIONS AND OBJECTIVES OF THE STANDARDS...........................................5 1.3 SCOPE ...................................................................................................................6

CHAPTER 2: GENERATION RELIABILITY STANDARD ......................................8 2.1 GENERATION PLANNING SECURITY CRITERIA ......................................................8 2.2 REQUIREMENTS ASSOCIATED WITH LOSS OF POWER INFEED................................8 2.3 GENERATION CONNECTION CRITERIA...................................................................9

2.3.1 General Generation Connection Requirements...............................................9 2.3.2 Planning Criteria for Generation Connections .............................................10 2.3.3 Operational Criteria for Generation Connections ........................................13

CHAPTER 3: TRANSMISSION RELIABILITY STANDARD.................................14 3.1 GENERAL ............................................................................................................14 3.2 TRANSMISSION ADEQUACY AND SECURITY CRITERIA ........................................15

3.2.1 Planning Criteria ...........................................................................................15 3.3.2 Operational Criteria ......................................................................................18 3.2.3 Mitigating Unsecured Contingency Events ...................................................21

3.3 DEMAND CONNECTON CRTERA .......................................................................23 3.3.1 General ..........................................................................................................23 3.3.2 Planning Criteria ...........................................................................................23 3.3.3 Operational Criteria ......................................................................................24

CHAPTER 4: PERFORMANCE CRITERIA AND LIMITS.....................................25 4.1 INTRODUCTION ...................................................................................................25 4.2 VOLTAGE ............................................................................................................25 4.3 VOLTAGE PERFORMANCE MARGN.....................................................................28 4.4 FREQUENCY LMTS ............................................................................................29 4.5 STABLTY LMTS...............................................................................................29 4.6 FAULT CLEARNG TMES.....................................................................................30 4.7 SHORT-CIRCUIT LIMITS ......................................................................................30 4.8 BASC INSULATON LEVEL ..................................................................................31 4.9 CRTERA FOR EVALUATNG UNSECURED CONTNGENCES ................................32 4.10 THERMAL LOADNG LMTS OF TRANSMSSON COMPONENTS............................33 4.11 SUMMARY OF TRANSMISSION SYSTEM REQUIREMENTS NORMAL AND EMERGENCY CONDITIONS...............................................................................................33


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TRANSMISSION SYSTEM POWER QUALITY STANDARDS..............................36 CONTENTS......................................................................................................................37 CHAPTER 1: INTRODUCTION...................................................................................38

1.1 POWER QUALITY DEFINITION AND REQUIREMENTS............................................38 1.2 SCOPE .................................................................................................................40

CHAPTER 2: TRANSMISSION POWER QUALITY STANDARDS.......................41 2.1 VOLTAGE SAG OR VOLTAGE DIP ........................................................................41 2.2 VOLTAGE STEP CHANGE.....................................................................................42 2.3 VOLTAGE FLUCTUATONS AND FLCKER.............................................................42 2.4 HARMONICS ........................................................................................................44 2.5 PHASE UNBALANCE AND TRACTION LOAD .........................................................46 2.6 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

A1 PURPOSE ...................................................................................................................67 A2 STANDARDS FOR BULK GENERATION, TRANSMISSION AND DELIVERY .....................70 A3 STANDARDS FOR DISTRIBUTION................................................................................71 A4 PROCESSES AND PROCEDURES ..................................................................................72 A5 SUMMARY .................................................................................................................77

APPENDIX B FOR TRANSMISSION SYSTEM RELIABILITY STANDARDS GUIDANCE ON ECONOMIC JUSTIFICATION OF GENERATION AND TRANSMISSION CONNECTIONS..............................................................................79

B1 GENERAL PRINCIPLES................................................................................................80 B2 GUDELNES...............................................................................................................80

APPENDIX C FOR TRANSMISSION SYSTEM RELIABILITY STANDARDS GUIDANCE ON SUBSTATION CONFIGURATIONS AND SWITCHING ARRANGEMENTS .........................................................................................................82

C1 GENERAL GUDANCE.................................................................................................83 C2 GENERATON PONT OF CONNECTON SUBSTATONS .................................................84 C3 MARSHALLNG SUBSTATONS....................................................................................84 C4 GRD SUPPLY PONT SUBSTATONS ...........................................................................84 C5(1) TYPICAL TNB SUBSTATION LAYOUT AND SWITCHING ARRANGEMENTS .............86 C5(2) TYPICAL TNB SUBSTATION LAYOUT AND SWITCHING ARRANGEMENTS CONTD........................................................................................................................................87

APPENDIX D FOR TRANSMISSION SYSTEM RELIABILITY STANDARDS ADDITIONAL CRITERIA TO LIMIT THE COMPLEXITY OF TRANSMISSION CIRCUITS........................................................................................................................88

D1 GENERAL PRINCIPLES ...............................................................................................89 D2 REQUREMENTS/RESTRCTONS.................................................................................89

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 Connected Customers. 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 a separate 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 is dictated 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 Transmission System 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 Interconnected Transmission System

Transmission radial networkand demand points

Distribution System

Embedded Distribution

Customers

DG

DG

Generation

Transmission

Distribution

GenerationReliability Standards

TransmissionReliability Standards

TransmissionPower Quality

Standards

Sufficient generation capacityand connections to deliver fullgeneration output for normal and Specific contingencies

GRID

COD

E

Sufficient transmission capacity to meet demand for specified contingencies

Meeting standards performance limits

Criteria for planning, designingand operating of transmission system to meet reliability and

power quality standards

Sufficient transformer capacity to meet demand

Power quality limits atinterfaces

Criteria for planning, designingand operating of distribution

system to meet supply security and power quality standards

STANDARDS CODES

DIST

RIBU

TION

COD

E

TOTALPOWERSYSTEMS

Transmission System

Reliability Standards

Distribution Supply Security and Power Quality Standards

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 as the 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 Circuit or 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 Units

shall 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 planned

such 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; or d) 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, under system 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 of

the 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 operational

Transmission System criteria which are set out in Chapter 3 of this Standard.

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 to ensure 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 Unsecured Contingency 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 that which 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 Station and 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 Insufficient

Voltage Performance Margins; or (4) 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.


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3.2.1.3 The minimum Transmission Capacity of the Main Interconnected Transmission 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 Reactive Power 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 (4) 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.

3.2.1.4 The minimum Transmission Capacity of the Main Interconnected Transmission

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: (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 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: (a) cascade tripping; and (b) System Instability.


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: (1) Unacceptable Overloading of any Primary Transmission Equipment;


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(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; (3) Unacceptable Overloading of any Primary Transmission Equipment; (4) Unacceptable Voltage Conditions; or (5) 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.

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:

(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); or

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


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(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 Infeed there shall not be:

(a) cascade tripping; and (b) System Instability.


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 post

fault 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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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 System Security.

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.


21

3.2.3 Mitigating Unsecured Contingency Events 3.2.3.1 In rare circumstances, disturbed System operating conditions, with multiple

outages 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;


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 on maintenance 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.


23

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 demand whose 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.

Transmission System Reliability Standards Chapter 4:Performance Criteria and Limits

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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 studies Nominal 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 at the Demand Supply Point from which it is derived, it is possible (for example by tap changing) to achieve at least 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 outside the limits set out in table 4.2.

Table 4.2: Unacceptable voltage limits in planning and operation

Planning Timescales Note 1

Operational Timescales Nominal Voltage

Maximum 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 Step Changes. 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 Secured Contingency Events

+10%

-2.5% for 500kV -5% for others Note 2

+10%

-2.5% for 500kV -5% for others Note 4

Following operational switching less frequent than specified in ER P28

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

Otherwise According to ER P28 Note 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 to voltage change taken into account.

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

Note 3 Following Voltage Step Change within these limits, it must be possible to restore the Steady State voltage to 95% of nominal at Demand Supply Points following any manual and/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, a section 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 or disconnection of Load (e.g., twice a day) Including capacitor banks and reactors

3%

Frequent switching and/or disconnection of 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 State conditions 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 3.2.1.4 of 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 required 47Hz - 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 normally

expected 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 100 500 and 275

Overhead Line/Cable 100 Substation 150

132 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 the switching 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 40kA, 3s for bulk substation 50kA, 1s for Power Station and 275kV within 500kV

substation 132 31.5kA, 3s

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, 3s Note: Typically closing-and-latching (momentary) capability of a circuit breaker as an rms current is not more than 1.6K times Symmetrical Short Circuit Rating or as an instantaneous 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 and

Distribution 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 132 650 33 170 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 defence

measures 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 Criteria Note 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 transmission elements in the immediate proximity to clear the fault which could not be normally cleared due to the stuck breaker

All Transmission Circuits and any transformers and/or reactive compensation equipment 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.

All Transmission Circuits 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 Criteria Note 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 for and 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 applicable time dependent emergency limit

Underground cables Strict observation of equipment continuous rating


Transformers No thermal overloading allowed


Switching and Isolation Equipment

Strict observation of equipment continuous rating

Applicable time dependent emergency limit

4.11 Summary of Transmission System Requirements Normal and Emergency Conditions

4.11.1 Table 4.12 summarises the required and/or expected performance of the

transmission system under four (4) categories of contingencies and for each category: (1) the initiating events and contingency elements; and (2) system performance requirements and expected impacts are 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 Conditions

Contingencies System Limits or Impacts

Category Initiating Event(s) and

Contingency Element(s) System Stable

& both Thermal and Voltage

Limits within Applicable

Rating Note (a)

Loss of Demand

or Curtailed

Firm Transfers

Cascading Outages

A No Contingencies

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3) Fault with Normal Clearing (Note (e)): 1. Generator 2. Transmission Circuit 3. Transformer Loss of an Element without a Fault

Yes Yes Yes Yes

No No No No

Note (b)

No No No No

B Event resulting in the loss of a single element

Single Pole Block, Normal Clearing (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 internal

fault)

Yes

Yes

Planned/ Controlled Planned/

Controlled Note (c)

No

No

SLG or 3 Fault, with Normal Clearing (Note (e)). Manual System Adjustment, followed by another SLG or 3 Fault, with Normal Clearing (Note (e)): 3. Category B (B1, B2, B3 or

B4) contingency, manual system adjustments, followed by another Category B(B1, B2, B3 or B4) contingency

Yes

Planned/ Controlled Note (c)

No

Bipolar Block with Normal Clearing (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/

Controlled Note (c)

No

No

C Event(s) resulting in the loss of two or more (multiple) elements

SLG Fault, with Delayed Clearing (stuck breaker or protection system failure) (Note (e)): 6. Generator 7. Transformer

8. Transmission Circuit

9. Bus Section

Yes

Yes

Yes

Yes

Note (c)

Planned/ Controlled Planned/

Controlled Planned/

Controlled Planned/

Controlled

No

No

No

No


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Contingencies System Limits or Impacts

Category Initiating Event(s) and

Contingency Element(s) System Stable

& both Thermal and Voltage

Limits within Applicable

Rating Note (a)

Loss of Demand

or Curtailed

Firm Transfers

Cascading Outages

D Extreme event resulting in two or more (multiple) elements removed or Cascading out of service Note (d)

3 Fault with Delayed Clearing (stuck breaker or protection system failure) (Note (e)): 1. Generator 2. Transmission (Circuit) 3. Transformer 4. 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 way 8. 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 center 12. Failure of a fully redundant Special Protection System to operate

when required 13. Operation, partial operation, or misoperation of a fully redundant

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

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

Elevate for risks and consequences: May involve

substantial loss of customer Demand and generation in a widespread area or areas

Portions or all of the interconnection systems may or may not achieve a new, stable operating point.

Evaluation of these events may require joint studies with neighboring systems.

Notes: (a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating (see table

4.11) or system voltage limit as determined and consistently applied specified in section 4.1 of this Standard. Applicable Ratings may include Emergency Ratings applicable for short durations as required to permit operating steps necessary to maintain system control.

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

(c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers (load shedding), the planned removal from service of certain generation, and/or the curtailment 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 contingency of Category D will be evaluated.

(e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected with proper functioning of the installed protection systems (see table 4.7). Delayed clearing 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 is when a three phase fault is cleared in normal clearing time followed by a SLG fault cleared after a delay time (to represent the single pole of a stuck breaker or protection system failure). Typical delay times are 250 milliseconds

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

Transmission System Power Quality Standards Contents

36

Transmission System Power Quality Standards

Effective January 1, 2006

Version 2.0 Edition 1.0

TENAGA NASIONAL BERHAD, 2006

Transmission System Power Quality Standards Contents

37

Contents

TRANSMISSION SYSTEM POWER QUALITY STANDARDS..............................36 CONTENTS......................................................................................................................37 CHAPTER 1: INTRODUCTION...................................................................................38

1.1 POWER QUALITY DEFINITION AND REQUIREMENTS............................................38 1.2 SCOPE .................................................................................................................40

CHAPTER 2: TRANSMISSION POWER QUALITY STANDARDS.......................41 2.1 VOLTAGE SAG OR VOLTAGE DIP ........................................................................41 2.2 VOLTAGE STEP CHANGE.....................................................................................42 2.3 VOLTAGE FLUCTUATONS AND FLCKER.............................................................42 2.4 HARMONICS ........................................................................................................44 2.5 PHASE UNBALANCE AND TRACTION LOAD .........................................................46 2.6 STEP CHANGES OF POWER ..................................................................................49

Transmission System Power Quality Standards Chapter 1: Introducton

38

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 that result 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 that Harmonic 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 Consumers equipment 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 and black 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 by

various 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.

Transmission System Power Quality Standards Chapter 2: Transmission Power Quality Standards

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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 be caused by short-circuit fault in one Users System and propagated to other Users Systems through the Transmission System.

2.1.3 In most cases, the Transmission System faults were cleared within the primary

protection fault clearing time. Statistics of monitored events of voltage sags indicates that not all faults on the Transmission System affect voltage sensitive customer demand. However for certain severe fault, the voltage sag may be felt by voltage sensitive customer up to (three hundred) 300km away from the fault location.

2.1.4 There is no single Standard for voltage sag but statistical information is available from TNB Transmission in terms of past records of voltage sag events. If Users or prospective Users have equipment which are sensitive to voltage sags, they can request such statistical information from TNB at the application stage to enable compatibility assessment to be carried out, if necessary. Whenever necessary, remedial actions may be rendered by TNB and/or the affected Customer through appropriate Agreement.


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2.2 Voltage Step Change 2.2.1 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 Step Changes. The voltage change is deemed unacceptable if it changes by more than the limits set out in Secton 4.2.4 of the Transmission System Reliability Standards.

2.2.2 Limits of voltage changes due to Load, frequent and infrequent operational

switching of Load both by TNB and the User are defined in Secton 4.2.5 of the Transmission System Reliability Standards.

2.3 Voltage Fluctuations and Flicker 2.3.1 The limits of Flicker that are acceptable on the Transmission System are in

accordance with the Engineering Recommendation P28, Issued by The Electricity Council of UK in 1989 entitled Planning Limits for Voltage Fluctuation Caused by Industrial, Commercial and Domestic Equipment in the United Kingdom (ER P28). TNB Transmission Division uses the procedures contained in this document to plan the connection of Fluctuating Loads and applies the limits therein in measuring and monitoring the levels of Flicker at such points of connection.

2.3.2 In accordance with ER P28, voltage fluctuations at a Point of Common Coupling

with a fluctuating Load directly connected to the Transmission System shall not exceed: (1) 1% of the voltage level for step changes, which may occur repetitively. Any

large voltage excursions other than step changes or less frequent step changes may be allowed up to a level of 3% provided that this does not constitute a risk to the Transmission System or, in TNBs view, any other party connected to the System.

(2) The planning limits for the Short and Long Term Flicker Severity applicable for Fluctuating Loads connected to the Transmission System are as set out in the table below (see table 2.1).


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Table 2.1: Maximum allowable flicker severity Transmission System

Voltage Level at which the Fluctuating Load is

Connected

Absolute Short Term Flicker Severity (Pst)

Absolute Long Term Flicker Severity (Plt)

500, 275 and 132kV 0.8 0.6 Less than 132kV 1.0 0.8

2.3.3 In connecting a Fluctuating Load at a particular point or Point of Common

Coupling it is necessary to assess the total Flicker due to the Fluctuating Load itself and the background Flicker measured at that point. In assessing the total Flicker TNB shall use the so called RSS Rule. This assessment is carried out by the RSS Rule by obtaining the sum of the squares of the Flicker from the Fluctuating Load and the background Flicker, with the square root of this sum yielding the total assessed Flicker at that Point of Common Coupling due to the specific Fluctuating Load and the background Flicker at that point.

2.3.4 Connection of more than one Fluctuating Load at the same Point of Common

Coupling or addition of further Fluctuating Load at the same location is carried out on a first come first served basis on the Transmission System. This means that whilst the first Fluctuating Load may be within the allowable Flicker limits and not require any Flicker mitigation or compensation equipment, the second Fluctuating Load which may cause violation of Flicker limits will be obliged to invest in appropriate Flicker mitigation or compensation e

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Malaysia Transmission System Reliability Standards