TNB_Tech Guidebook for the Connection of Generation to the Distn Network

Tenaga Nasional Berhad TNB Research

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First Edition, March 2005

Technical Guidebook for the Connection of Generation to

the Distribution Network

Prepared by:

TNB Research Sdn. Bhd.

in Collaboration with:

APS Sdn. Bhd., Malaysia RWE Npower plc, United Kingdom

1_DG_Technical_GUIDEBOOK_Edition_1_MARCH_2005


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TTaabbllee ooff CCoonntteennttss TABLE OF CONTENTS ........................................................................................ 2 TABLE OF CONTENTS

CONTRIBUTORS .............................................................................................. 7 CONTRIBUTORS

PREFACE....................................................................................................... 8 PREFACE

CHAPTER 1: INTRODUCTION...............................................................................10 CHAPTER 1: INTRODUCTION

1.1 BACKGROUND ....................................................................................................................10 1.1 BACKGROUND

1.2 OBJECTIVES OF THE GUIDEBOOK............................................................................................11 1.2 OBJECTIVES OF THE GUIDEBOOK

1.3 DEFINITIONS OF KEY TERMS USED IN THE GUIDEBOOK ..............................................................12 1.3 DEFINITIONS OF KEY TERMS USED IN THE GUIDEBOOK

1.4 GUIDEBOOK APPROACH .......................................................................................................13 1.4 GUIDEBOOK APPROACH

1.5 STATUTORY ACTS, REGULATIONS, RULES AND CODES ..............................................................14 1.5 STATUTORY ACTS, REGULATIONS, RULES AND CODES

1.6 SCOPE OF THE GUIDEBOOK ...................................................................................................14 1.6 SCOPE OF THE GUIDEBOOK

1.7 USING THIS GUIDEBOOK.......................................................................................................15 1.7 USING THIS GUIDEBOOK

1.8 CONTENTS OF THE GUIDEBOOK..............................................................................................15 1.8 CONTENTS OF THE GUIDEBOOK

CHAPTER 2: PROCESS FOR GETTING CONNECTED.....................................................17 CHAPTER 2: PROCESS FOR GETTING CONNECTED

2.1 SUMMARY OF PROCESS .......................................................................................................17 2.1 SUMMARY OF PROCESS

2.2 PROJECT PLANNING ............................................................................................................20 2.2 PROJECT PLANNING

2.3 EXCHANGE OF PLANNING INFORMATION & PRELIMINARY STUDY.................................................21 2.3 EXCHANGE OF PLANNING INFORMATION & PRELIMINARY STUDY

2.4 PROJECT DESIGN................................................................................................................22 2.4 PROJECT DESIGN

2.5 PROJECT CONSTRUCTION.....................................................................................................23 2.5 PROJECT CONSTRUCTION

2.6 PROJECT TESTING AND COMMISSIONING ................................................................................23 2.6 PROJECT TESTING AND COMMISSIONING

2.7 DG OPERATION..................................................................................................................23 2.7 DG OPERATION

CHAPTER 3: TECHNICAL ISSUES AND REQUIREMENTS FOR CONNECTION ........................24 CHAPTER 3: TECHNICAL ISSUES AND REQUIREMENTS FOR CONNECTION

3.1 RESPONSIBILITIES OF THE DISTRIBUTORS TO CUSTOMERS AND THE DGS .....................................24 3.1 RESPONSIBILITIES OF THE DISTRIBUTORS TO CUSTOMERS AND THE DGS

3.2 QUALITY OF SUPPLY REQUIREMENTS .....................................................................................24 3.2 QUALITY OF SUPPLY REQUIREMENTS

3.3 TECHNICAL ISSUES..............................................................................................................28 3.3 TECHNICAL ISSUES

3.4 VOLTAGE CONTROLS AND REGULATIONS.................................................................................28 3.4 VOLTAGE CONTROLS AND REGULATIONS

3.5 FAULT LEVELS....................................................................................................................32 3.5 FAULT LEVELS

3.6 NETWORK/FEEDER CAPACITY AND SECURITY ASSESSMENTS......................................................34 3.6 NETWORK/FEEDER CAPACITY AND SECURITY ASSESSMENTS

3.7 SUPPLY QUALITY – RELIABILITY AND POWER QUALITY .............................................................38 3.7 SUPPLY QUALITY – RELIABILITY AND POWER QUALITY

3.8 PROTECTION AND CONTROLS................................................................................................39 3.8 PROTECTION AND CONTROLS

3.8.1 General.......................................................................................................................39 3.8.1 General3.8.2 Short term Occasional Parallel Operation ................................................................40 3.8.2 Short term Occasional Parallel Operation3.8.3 Loss of Mains.............................................................................................................40 3.8.3 Loss of Mains3.8.4 Auto-reclosing............................................................................................................42 3.8.4 Auto-reclosing3.8.5 Islanded Operation.....................................................................................................42 3.8.5 Islanded Operation

3.9 LOSSES.............................................................................................................................44 3.9 LOSSES

3.10 EARTHING AND USE OF INTERFACE TRANSFORMERS...................................................................46 3.10 EARTHING AND USE OF INTERFACE TRANSFORMERS

3.11 STABILITY .........................................................................................................................47 3.11 STABILITY

3.12 OVER VOLTAGES AND RESONANT OVER-VOLTAGE......................................................................47 3.12 OVER VOLTAGES AND RESONANT OVER-VOLTAGE

3.13 DATA REQUIREMENTS..........................................................................................................48 3.13 DATA REQUIREMENTS

3.14 SAFETY .............................................................................................................................48 3.14 SAFETY


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CHAPTER 4: PLANNING, CONNECTION AND OPERATION OF THE DGS..............................50 CHAPTER 4: PLANNING, CONNECTION AND OPERATION OF THE DGS

4.1 INTRODUCTION...................................................................................................................50 4.1 INTRODUCTION

4.2 PRELIMINARY PLANNING STUDY ...........................................................................................50 4.2 PRELIMINARY PLANNING STUDY

4.2.1 Objective ....................................................................................................................50 4.2.2 Connection Facilities Under the Distributor’s Responsibility...................................51 4.2.3 Basic Connection Issues............................................................................................54 4.2.3 Basic Connection Issues4.2.4 Preliminary System Study Procedure........................................................................55 4.2.4 Preliminary System Study Procedure4.2.5 Basic Protection, Control, Metering and Monitoring Requirements ........................56 4.2.5 Basic Protection, Control, Metering and Monitoring Requirements4.2.6 Preliminary System Study Report .............................................................................56

4.3 POWER SYSTEM STUDY.......................................................................................................57 4.3 POWER SYSTEM STUDY

4.3.1 Objectives: .................................................................................................................57 4.3.2 Data Requirements ....................................................................................................57 4.3.3 Power System Study Methods and Analyses.............................................................58 4.3.4 Additional Analysis in Power System Study..............................................................59 4.3.5 Power System Study Report and Liaison ..................................................................62

4.4 CONNECTION OF THE DG PLANT TO THE DISTRIBUTION NETWORK...............................................62 4.4 CONNECTION OF THE DG PLANT TO THE DISTRIBUTION NETWORK

4.4.1 Connection Point and Connection Process................................................................62 4.4.2 Protection Coordination Study ...................................................................................62 4.4.3 Protective Equipment Tests and Settings..................................................................64 4.4.3 Protective Equipment Tests and Settings4.4.4 Inspection and Pre-Commissioning Tests.................................................................65 4.4.4 Inspection and Pre-Commissioning Tests4.4.5 Commissioning Procedure.........................................................................................66 4.4.5 Commissioning Procedure4.4.6 Plant Commissioning and Tests ................................................................................67 4.4.6 Plant Commissioning and Tests4.4.7 Establishment of ‘Connection Operation Manual’.....................................................68 4.4.7 Establishment of ‘Connection Operation Manual’

4.5 OPERATION OF THE DG PLANT WITH THE DISTRIBUTION NETWORK .............................................70 4.5 OPERATION OF THE DG PLANT WITH THE DISTRIBUTION NETWORK

4.5.1 Control Operation.......................................................................................................70 4.5.2 DG Operating Modes..................................................................................................70 4.5.3 Distribution Operation Planning ................................................................................72 4.5.4 Exchange of Operational Information ........................................................................72 4.5.5 Operating and Safety Requirements .........................................................................74

CHAPTER 5: INTERFACE DESIGN REQUIREMENTS AND NETWORK REINFORCEMENTS..........75 CHAPTER 5: INTERFACE DESIGN REQUIREMENTS AND NETWORK REINFORCEMENTS

5.1 INTRODUCTION...................................................................................................................75 5.1 INTRODUCTION

5.2 BASIC CONNECTION INTERFACE REQUIREMENTS.......................................................................76 5.2 BASIC CONNECTION INTERFACE REQUIREMENTS

5.2.1 Isolation .....................................................................................................................76 5.2.2 Connection through Star-Delta Transformer .............................................................77

5.3 UTILITY ACCESS .................................................................................................................78 5.3 UTILITY ACCESS

5.4 SYNCHRONISATION .............................................................................................................79 5.4 SYNCHRONISATION

5.5 PROTECTION AND CONTROL..................................................................................................80 5.5 PROTECTION AND CONTROL

5.5.1 Protection...................................................................................................................80 5.5.1 Protection5.5.2 Controls......................................................................................................................82 5.5.2 Controls

5.6 INTERLOCKING....................................................................................................................84 5.6 INTERLOCKING

5.8 SCADA AND AUTOMATION...................................................................................................86 5.8 SCADA AND AUTOMATION

5.9 COMMUNICATIONS..............................................................................................................87 5.9 COMMUNICATIONS

CHAPTER 6: GLOSSARY ....................................................................................89 CHAPTER 6: GLOSSARY

6.1 GENERAL TERMS ................................................................................................................89 6.1 GENERAL TERMS

6.2 OTHER TERMS .................................................................................................................101 6.2 OTHER TERMS


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7. APPENDIX A: SUMMARY OF TNB POWER SYSTEMS........................................... 108 7. APPENDIX A: SUMMARY OF TNB POWER SYSTEMS

7.1 INDUSTRY STRUCTURE ......................................................................................................108 7.1 INDUSTRY STRUCTURE

7.1.1 A Brief History of Electricity Industry in Malaysia...................................................108 7.1.2 Electricity Industry Reform ......................................................................................108 7.1.3 Renewable Energy (RE) and The Small Renewable Energy Programme (SREP) ..108 7.1.4 Current structure of electricity industry...................................................................108 7.1.5 Regulation and Licensing ........................................................................................110

7.2 POWER GENERATION.........................................................................................................111 7.2 POWER GENERATION

7.2.1 Generation Entities ..................................................................................................111 7.2.2 Generation Mix.........................................................................................................111 7.2.3 Self Generation and Co-generation .........................................................................112

7.3 TRANSMISSION AND POWER SYSTEM OPERATION ..................................................................112 7.3 TRANSMISSION AND POWER SYSTEM OPERATION

7.3.1 Transmission System...............................................................................................112 7.3.2 Power System Operation .........................................................................................114

7.3.2.1 Load forecasting ...............................................................................................114 7.3.2.2 Planning & Investment......................................................................................114 7.3.2.3 Operational planning .........................................................................................115 7.3.2.4 Control operation (NLDC) .................................................................................115

7.3.3 Control of System Frequency...................................................................................115 7.3.4 Control of System Voltage .......................................................................................115

7.4 DISTRIBUTION..................................................................................................................116 7.4 DISTRIBUTION

7.4.1 Distribution Organisations.......................................................................................116 7.4.2 Voltages ...................................................................................................................116 7.4.3 Protection in Distribution Networks.........................................................................116

7.4.3.1 Fault and fault current .......................................................................................116 7.4.3.2 Protection system.............................................................................................117 7.4.3.3 Fault level and equipment rating .......................................................................117

7.4.4 Distribution Network Planning.................................................................................118 7.4.5 Control and Operation of Distribution Network .......................................................118

8. APPENDIX B: TYPES OF DGS ...................................................................... 120 8. APPENDIX B: TYPES OF DGS

8.1 INTRODUCTION.................................................................................................................120 8.1 INTRODUCTION

8.1.1 Energy Source ..........................................................................................................120 8.2 HYDROPOWER..................................................................................................................120 8.2 HYDROPOWER

8.3 FUEL CELLS .....................................................................................................................122 8.3 FUEL CELLS

8.4 LANDFILL GAS..................................................................................................................123 8.4 LANDFILL GAS

8.5 WIND POWER ..................................................................................................................123 8.5 WIND POWER

8.6 MICROTURBINES...............................................................................................................125 8.6 MICROTURBINES

8.7 GEOTHERMAL...................................................................................................................125 8.7 GEOTHERMAL

8.8 PHOTOVOLTAIC.................................................................................................................126 8.8 PHOTOVOLTAIC

8.9 COGENERATION ................................................................................................................126 8.9 COGENERATION

8.9.1 Definitions of Cogeneration .....................................................................................126 8.9.2 Cogeneration plants in Malaysia.............................................................................128 8.9.3 Description of Cogeneration Technologies .............................................................130

8.9.3.1 Back-pressure steam turbine ................................................................................130 8.9.3.2 Pass-out condensing steam turbine......................................................................131 8.9.3.3 Gas Turbine...........................................................................................................131


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9. APPENDIX C: DATA AVAILABLE AND TO BE SUBMITTED ...................................... 133 9. APPENDIX C: DATA AVAILABLE AND TO BE SUBMITTED

9.1 DATA AVAILABLE FROM TNB AT THE INITIAL STAGE................................................................133 9.2 DATA TO BE SUBMITTED BY DG DEVELOPER FOR ‘PRELIMINARY SYSTEM STUDY’ – ES.08.01 ......134 9.3 DATA TO BE SUBMITTED FOR ‘POWER SYSTEM STUDY’ – ES.08.03..........................................135

10. APPENDIX D: TNB DISTRIBUTION PLANNING CRITERIA.................................... 139 10. APPENDIX D: TNB DISTRIBUTION PLANNING CRITERIA


10.2 DISTRIBUTION NETWORK DESIGN PHILOSOPHY .....................................................................139 10.2 DISTRIBUTION NETWORK DESIGN PHILOSOPHY

10.3 NETWORK CAPACITY AND REINFORCEMENT NEEDS.................................................................139 10.3 NETWORK CAPACITY AND REINFORCEMENT NEEDS

10.4 DISTRIBUTION SYSTEM PLANNING/DESIGN CRITERIA..............................................................140 10.4 DISTRIBUTION SYSTEM PLANNING/DESIGN CRITERIA

10.4.1 Steady State Criteria............................................................................................140 10.4.2 Steady State Voltage limits .................................................................................140 10.4.3 Thermal Ratings Limits .......................................................................................141 10.4.4 Fault Level Ratings Limits (Short-circuit Rating) ...............................................141 10.4.5 Frequency Limits .................................................................................................141 10.4.6 Security of Supply Criteria under Contingency Situation....................................141

10.4.6.1 Network Reliability ............................................................................................141 10.4.6.2 Urban/Sub-Urban Medium Voltage Distribution Feeders ..................................141 10.4.6.3 Rural Medium Voltage Distribution Feeders (<1 MVA)......................................142 10.4.6.4 Low Voltage Distribution Networks...................................................................142

10.4.7 Power Quality Criteria .........................................................................................142 10.4.7.1 Power quality under steady-state conditions ....................................................142 10.4.7.2 Power quality during transient disturbance conditions .....................................142 10.4.7.3 System Frequency.............................................................................................142 10.4.7.4 TNB Power Quality Compatibility Limits............................................................143

TABLE 10.1 - TNB POWER QUALITY COMPATIBILITY STANDARDS AND GUIDELINES ................................143 10.4.8 Conductor Selection Criteria................................................................................144

11. APPENDIX E: SYSTEM STUDIES ASSOCIATED WITH THE CONNECTION OF THE DG ... 145 11. APPENDIX E: SYSTEM STUDIES ASSOCIATED WITH THE CONNECTION OF THE DG


11.2 PRELIMINARY SYSTEM STUDY ............................................................................................146 11.2 PRELIMINARY SYSTEM STUDY

11.2.1 Generating unit data ............................................................................................146 11.2.2 Review/Update Network Model ...........................................................................149 11.2.3 Connecting DG Plant and Modelling Approach ...................................................150 11.2.4 Network Voltage Profile .......................................................................................152

11.2.4.1 Voltage Profile Without the DG .........................................................................153 11.2.4.2 Voltage Profile DG at the end of feeder .............................................................154 11.2.4.3 Voltage Profile DG at the mid of feeder ...............................................................155 11.2.4.4 Voltage Profile DG at the source of feeder ........................................................156 11.2.4.5 Voltage Profile DG at end of feeder with additional 11kV feeder .........................157 11.2.4.6 Voltage Profile DG at end of feeder with 33kV feeder connection .....................158

11.2.5 System Losses .....................................................................................................160 11.2.5.1 Losses DG at the end of the feeder ...................................................................160 11.2.5.2 Losses DG at the mid of the feeder ...................................................................161 11.2.5.3 Losses DG at the source of the feeder ..............................................................162

11.2.6 Short-Circuit Analysis ..........................................................................................163 11.2.7 System/Feeder Adequacy ....................................................................................165


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11.3 POWER SYSTEM STUDY.....................................................................................................167 11.3 POWER SYSTEM STUDY

11.3.1 Stability Analysis .................................................................................................167 11.3.1.1 Models for Excitation Control..............................................................................167 11.3.1.2 Models for Speed-Governor................................................................................167 11.3.1.3 PSS/ADEPT Network Model to PSS/E Dynamics.................................................167 11.3.1.4 Stability Analysis.................................................................................................171

11.3.2 Insulation Coordination Analysis.........................................................................172

12. APPENDIX F: PROTECTION AND CONTROL REQUIREMENTS .............................. 173 12. APPENDIX F: PROTECTION AND CONTROL REQUIREMENTS


12.2 TYPES OF PROTECTION REQUIREMENTS................................................................................173 12.2 TYPES OF PROTECTION REQUIREMENTS

12.3 DISTRIBUTED GENERATOR PROTECTION SCHEME ...................................................................177 12.3 DISTRIBUTED GENERATOR PROTECTION SCHEME

12.4 SUMMARY OF TNB’S DISTRIBUTION PROTECTION PRACTICES ..................................................178 12.4 SUMMARY OF TNB’S DISTRIBUTION PROTECTION PRACTICES

12.4.1 General Requirement...........................................................................................178 12.4.1.1 Maximum Fault Clearing Time, Operating and Reset Time................................178 12.4.1.2 Protection Relays..............................................................................................178 12.4.1.2 Protection Relays

12.4.2 Protection Scheme Policy....................................................................................179 12.4.2.1 Overhead Line Feeder Protection ......................................................................179 12.4.2.1 Overhead Line Feeder Protection12.4.2.2 Underground Cable Feeder Protection ..............................................................179 12.4.2.2 Underground Cable Feeder Protection12.4.2.3 Transformer Protection.....................................................................................180 12.4.2.3 Transformer Protection12.4.2.4 Busbar Protection ...............................................................................................181 12.4.2.4 Busbar Protection

12.5 COORDINATION BETWEEN DG AND DISTRIBUTION PROTECTION.................................................181 12.5 COORDINATION BETWEEN DG AND DISTRIBUTION PROTECTION

12.6 SCADA/DA REQUIREMENTS..............................................................................................182 12.6 SCADA/DA REQUIREMENTS

12.6.1 Basic SCADA ........................................................................................................182 12.6.2 SCADA Practices in TNB and Requirements .......................................................182 12.6.3 Master System .....................................................................................................183

12.6.3.1 Master Station.....................................................................................................184 12.6.3.1 Master Station.

13. APPENDIX G: CONNECTION AGREEMENT..................................................... 185 13. APPENDIX G: CONNECTION AGREEMENT

13.1 GENERAL.........................................................................................................................185 13.1 GENERAL

13.2 CONNECTION AGREEMENT ..................................................................................................185 13.2 CONNECTION AGREEMENT

13.2.1 Description of Facility and Site. ..........................................................................185 13.2.2 Design & Operations Standard ............................................................................186 13.2.3 Energy Accounting and Metering Equipment. .....................................................186 13.2.4 Interconnection Facilities....................................................................................186 13.5.2 Communication Facilities ....................................................................................187 13.5.3 Electricity Characteristics....................................................................................187

13.3 CONNECTION OPERATION MANUAL...........................................................................................188 13.3 CONNECTION OPERATION MANUAL.


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CCoonnttrriibbuuttoorrss Many individuals have made contributions to the Guidebook. However, the following persons have made major contributions and deserve to be recorded here: No Name Organisation 1 Halim Osman TNB Distribution 2 Dr. Fadzil Mohd Siam TNB Research 3 Dr. Sallehhudin Yusof APS Sdn. Bhd. 4 Hamzah Ngah RWE Npower, plc 5 Abu Hanifah Azit TNB IT 6 Abdul Aziz Majid TNB Distribution 7 Loo Chin Koon TNB Distribution 8 Asnawi TNB Research


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PPrreeffaaccee This “Technical Guidebook for the Connection of Generation to the Distribution Network” published by Tenaga Nasional Berhad (TNB) is intended to be used by DG (Distributed Generation) Developers, Plant Managers/Engineers, Consultants and Utility Engineers as guidelines for the planning of the connection of a distributed generation to the distribution network. This Guidebook will be applicable from March 2005. The focus of this Guidebook is on connection planning of DG Plants to the distribution network. However, a good plan always takes into consideration other related issues particularly DG plant operation. Therefore, if other ancillary subjects apart from planning of connections are discussed, the intention is complementary thus may not be dealt with in full. In this Guidebook, Distributed Generation (DG) Plant is defined as a plant comprising of one or more generating units that is connected to the distribution network at the medium voltage level and whose total power output will be scheduled at all times to be totally consumed by loads in that distribution network (see chapter 1). The types of generating units addressed in this Guidebook include both synchronous and asynchronous. The Guidebook first discusses typical steps involved in connecting DG plant to the distribution network (see chapter 2). The process starts with the DG Developer contacting TNB district or regional offices right up to testing and commissioning as well as identifying list of requirements for successful operation of the plant. Before discussing the requirements for connection of the DG plant to the distribution network, technical issues are discussed so that their understanding will lead to an appreciation on how each of the issues is resolved (in chapter 3). Not all technical issues are required to be resolved unless they cause problems to the distribution network and its customers. The Guidebook in chapter 4 discusses how planning and design studies are carried out and how each of the technical issues is identified, assessed and resolved. The chapter also discusses how connection is established and the operation of the DG with the distribution network. The Guidebook summarises interface requirements and possible distribution network reinforcements in chapter 5. Chapter 6 defines all the terms used in the Guidebook. Appendices A through G are provided to support main chapters of the Guidebook. These appendices contain detailed technical contents of the subjects discussed including case studies and worked examples. Although, the Guidebook is comprehensive in its contents, it is not intended to present total solutions to all design and connection issues. It is also not intended to be prescriptive, thus Distributors, Developers and Consultants have still to work on mutually acceptable, safe and optimal solution for every case.


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Chapter 1 – Introduction Objectives, basic definitions, scope, summary of

contents

Summary of the Contents of the Guidebook

Chapter 2 – Procedures for Getting ConnectedDescribes steps involved in process of getting

connected from initial contact with TNB to testing/commissioning and operation

Chapter 3 – Technical Issues Associated with Connections of Distributed Generation

Describes all possible technical issues that may arise with the connection of DG to the distribution

network

Chapter 4 – Planning, Connection and Operation of the DGs

Describes planning and design approaches to identify issues and resolve them. Discusses how

issues are tackled during connection and operation.

Chapter 5 – Interface Design Requirements and Network Reinforcements

Summarises interface requirements including typical network reinforcements.

Chapter 6 – GlossaryDefinition of terms

Chapter 1 – IntroductionObjectives, basic definitions, scope, summary of

contents

Chapter 2 – Procedures for Getting ConnectedDescribes steps involved in process of getting

connected from initial contact with TNB to testing/commissioning and operation

Chapter 3 – Technical Issues Associated with Connections of Distributed Generation

Describes all possible technical issues that may arise with the connection of DG to the distribution

network

Chapter 4 – Planning, Connection and Operation of the DGs

Describes planning and design approaches to identify issues and resolve them. Discusses how

issues are tackled during connection and operation.

Chapter 5 – Interface Design Requirements and Network Reinforcements

Summarises interface requirements including typical network reinforcements.

Chapter 6 – GlossaryDefinition of terms

Appendix A – GSupporting chapters, detailed methods/procedures

and case studies

Appendix A – GSupporting chapters, detailed methods/procedures

and case studies


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CChhaapptteerr 11:: IInnttrroodduuccttiioonn

11..11 BBaacckkggrroouunndd 1.1.1 In 1996 Tenaga Nasional Berhad (TNB) published a document entitled

“Technical Guidebook for the Interconnection of Distribution Generators to TNB’s Medium Voltage Distribution Network”, hereafter referred to as the “1996 Interconnection Guidebook”. Since then rapid development of distributed generation (DG) coupled with experience gained in planning, design and operation by both TNB and DG Developers/Operators have compelled the electricity industry to review the technical guidelines for the connection of the DGs to ensure some transparencies in the processes and removal of any foreseeable technical barriers. Furthermore, in the country’s recently revised Fuel Diversification Policy, the use renewable energy (RE) has been intensified and incorporated as the fifth fuel that obliges the electricity distribution industry players to encourage connections of RE-based DGs to the distribution network to make the policy a success1.

1.1.2 This Guidebook is a complete revision of the “1996 Interconnection Guidebook”

and has incorporated all the important issues to be addressed before connecting of a DG to the distribution network. The approach to this revised Guidebook is to have chapters briefly addressing all issues. Where necessary, the appendices will elaborate on the subject matter supplemented with case studies. Prior to the launching of this review work, DG stakeholders have participated in two workshops and one meeting that resulted in a list of technical and commercial issues that need to be addressed further. Many of the technical issues and selected commercial concerns are addressed in this Guidebook.

1.1.3 This “Technical Guidebook for the Connection of Generation to the Distribution

Network” (“the DG Guidebook” or ”the DG Connection Guidebook”) is intended for use mainly by DG Developers and Distribution Utility engineers for planning, design and operation of the DGs. Since the Guidebook will also cover all possible types of synchronous/asynchronous generator connections to the distribution network, either directly or indirectly, it is also a useful reference to consulting engineers, factory engineers and plant operators.

1.1.4 There are many tasks to be carried out and issues to be addressed in order to

successfully implement a DG Plant project. This Guidebook focuses only on connection of DG Plant to the distribution network. Technical matters associated with energy conversion, mechanical design of DG plant, environmental protection, etc. is beyond the scope of this Guidebook. However, in order to make clear some issues, other supplementary subjects not explicitly related to connection may also be discussed.

1. Refer “Guidelines on Small Renewable Energy Programme (SREP)”, Suruhanjaya Tenaga, Malaysia, not dated.


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1.1.5 The DG Guidebook has been written based on the prevalent electricity industry structure in Peninsular Malaysia, its regulatory framework and utility industry practices. The industry structure, regulation and practices may change from time to time and when necessary relevant parts of this Guidebook will be revised accordingly.

11..22 OObbjjeeccttiivveess ooff tthhee GGuuiiddeebbooookk 1.2.1 The main objective of this DG Connection Guidebook is to provide guidance on

the step-by-step process and procedures involved from DG Developers initiation of distributed generation to its connection to the distribution network as well as its commissioning and operation. The Guidebook is designed to give guidance on all technical aspects of the DG connection and may therefore have different objectives from the perspectives of DG Developers or Utility Engineers.

1.2.2 DG Developers/Operators may use this Guidebook for several purposes,

including:

a) To understand how electricity distribution system works; b) To identify what information and their details that can be obtained from TNB

with respect to connecting a DG plant; c) To find out what types of schemes and equipment required for connecting

the DG to distribution network and why they are necessary; d) To understand what supply quality standards are imposed by the Regulator

on a utility like TNB and how a DG could contribute either positively or negatively to supply quality and security;

e) To understand how a utility like TNB carries out planning studies to dimension the interface connection and why reinforcements in the distribution network may become necessary; and

f) To understand how a DG is operated with the distribution network and how operational planning is carried out.

1.2.3 Utility planning, design and operation engineers could refer to the DG

Guidebook for several purposes but not limited to the following:

a) To find out what information could be requested from DG Developers; b) To check compliance of the DG interface design with the standard

requirements; c) To find out what typical parameters could be used to model the DG plant for

the purposes of studies when first proposed by the Developer; d) To identify the proper steps and methods to be used in conducting system

studies and the timescales involved; e) To establish cost estimates of connection to be provided to the DG

Developer; and f) To find out what options could be used to resolve technical problems

identified during planning and design analysis.


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11..33 DDeeffiinniittiioonnss ooff KKeeyy TTeerrmmss UUsseedd iinn tthhee GGuuiiddeebbooookk 1.3.1 Distributed Generation (DG) or Embedded Generation (EG) is defined as the

production of electrical power by converting another form of energy in a generating unit that is connected to a distribution system. In this Guidebook, a DG Plant is defined “as a generating plant comprising of one or more generating units that is connected to the distribution network at the medium voltage level and whose total power output will be scheduled at all times to be totally consumed by loads in that distribution network”. As illustrated in Figure 1.1, the output power of the DG is scheduled not to spill over to the transmission network to avoid reverse power flow at the interface of transmission and distribution networks.

G

DistributedGeneration

Distribution Network

TransmissionNetwork

Power Flow

Power Flow

Figure 1.1: Distributed generation 1.3.2 In practice the total capacity of a DG Plant connected to the medium voltage

network could vary from hundreds of kW to 20MW as long as the generated power does not at any time spill over to the transmission network. However, any generating plant intended to be connected to the Transmission Grid (Grid System) must be referred to the Grid System Operator (currently assumed by the System Planning Department of TNB).

1.3.3 Distributed or Embedded Generating Unit is a generating unit connected within a

distribution network and not having direct access to the transmission network. This includes an Embedded Generator connected to its own network whose network is interconnected with the Distribution network either directly or through an interface transformer.

Load

G

DistributedGeneration

Distribution Network

TransmissionNetwork

Power Flow

Power Flow

Load


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1.3.4 A Distribution Network is defined as a system comprising of electrically connected equipment or elements that produce, transport, transform, control, and consume electrical power at medium and low voltage levels not greater than 33kV nominal.

1.3.5 A Distribution System is defined as a system consisting (wholly or mainly) of

electrical lines which are owned and operated by a Distributor and used for the distribution of electricity from Grid Supply points or Generating Units or other entry points to the point of delivery to Customers or Other Distributors.

1.3.6 A Distribution System Operator or Distributor is a person or organisation who is

responsible for the management of any portion of a distribution system or for directing its operations during normal or emergency conditions.

1.3.7 A Distributed Generation Developer (DG Developer) is a person or organisation

who develops or owns a generating plant that is intended to be connected to the distribution network.

1.3.8 A Distributed Generation Operator (DG Operator) is a person or organisation who

is responsible for the management, operation, maintenance and safety of a generating plant and its associated network connected to the distribution network.

1.3.9 A Renewable Energy Plant (RE Plant)1 is a DG Plant that is categorized under the

Small Renewable Energy Programme (SREP) that is being coordinated by a Special Committee on Renewable Energy (SCORE).

1.3.10 Medium Voltage or MV is any voltage equal to or exceeding 1kV but not

exceeding nominal 33 kV. Low Voltage or LV is any voltage level less than 1000 volts or 1 kV.

1.3.11 Grid System or the Grid is the system consisting (wholly or mainly) of high

voltage, namely nominal 500kV, 275kV, 132kV, and 66kV transmission lines owned and operated by Tenaga Nasional Berhad (TNB) and used for the transmission of electricity from one power station to a substation or to another power station or between substations or to or from any external interconnection, and includes any Plant and Apparatus and meters owned or operated by TNB in connection with the transmission of electricity.

11..44 GGuuiiddeebbooookk AApppprrooaacchh 1.4.1 The Guidebook is written to address all possible technical issues associated

with the connection of the DGs to the distribution network. All these technical issues will at least be discussed in one of the five chapters of this Guidebook and the details of which would be provided in the appendices, if necessary. In other words, the first five chapters contain pointers to more detail account of the subjects related to connections of the DGs.


- 14 –


1.4.2 The Guidebook is structured to allow for any amendment to the detailed technical contents and the case studies be updated separately and independently through the additions or amendments of the appendices.

11..55 SSttaattuuttoorryy AAccttss,, RReegguullaattiioonnss,, RRuulleess aanndd CCooddeess 1.5.1 This Guidebook may also refer to relevant legal documents that exist in Malaysia

including acts, regulations, codes, rules and guidelines. Since these documents are subject to revision and amendments by the appropriate authority, readers should always ensure that they consult the latest versions.

1.5.2 The relevant safety, electricity production, transmission, distribution and supply

licensing, legal and regulatory requirement are mandatory and nothing in the Guidebook shall be taken to relieve these legal or regulatory obligations in the provisions of: 1) The Electricity Supply Act 1990; 2) The Occupational Safety and Health Act 1994; 3) The Electricity Regulations 1994; 4) The Environmental Quality Act 1974; 5) Factories and Machinery (Noise Exposure) Regulation 1989; 6) Licence issued by the Suruhanjaya Tenaga to industry players; 7) The Malaysian Grid Codes; 8) TNB's Safety Regulation; 9) The Malaysian Distribution Code (when available). With respect to the "The Environmental Quality Act 1974", only relevant provision shall be applied to DG Plant such as effluent discharge (under Environment Quality (Prescribe Premises - Crude palm Oil) Regulation 1977), Emission (under Environmental Quality (Clean Air) Regulation 1978) addressing issues such as open burning.

1.5.3 There are also guidelines published by authorities including the Ministries and

the Energy Commission that are complementary to this Guidebook and therefore DG Developers and Utility Engineers are encouraged to refer to those documents.

1.5.4 A DG plant that is to be connected to the distribution network must be designed

to be compatible with the particular distribution network to which it is to be connected and the Grid System.

11..66 SSccooppee ooff tthhee GGuuiiddeebbooookk 1.6.1 This Guidebook addresses technical issues associated with the connection of a

DG to the distribution network. Therefore, commercial issues are not addressed except those necessary without which the subject cannot be fully dealt with.

1.6.2 There are many other issues that will not be addressed by this Guidebook

because they are only the concern of either the Developer or the Distributor and


- 15 –


not with the connection. Issues such as: identifying and obtaining fuel supplies, project financing, power sales and purchase negotiations, DG plant design, getting approval of local authorities, land matters etc. are some of the subjects not covered by this Guidebook.

11..77 UUssiinngg tthhiiss GGuuiiddeebbooookk 1.7.1 If you have reached this point of the book you should by now have basic

understanding of the background to the Guidebook and its objectives. Chapter 2 outlines the general procedures for getting connected and therefore is referred to as the root of the Guidebook from which all other chapters and appendices are referred to.

1.7.2 After understanding the basic procedures for getting connected, a reader may

then refer directly to the relevant chapters and appendices for details. To scan through all technical issues related to connection of a DG plant one can refer to chapter 3. Each of the technical issue is discussed in a brief and concise manner in a section in chapter 3 and the details of which would be found in an appendix or appendices of the Guidebook.

1.7.3 Technical issues related to the connection of DG plants are usually addressed at

the planning stage. Two main activities carried out during planning are system and design studies and these activities are discussed in chapter 4. A reader who is interested to find out how TNB performs preliminary planning study or design studies should first refer to the relevant sections in chapter 4 and the associated appendices.

1.7.4 If a reader intends to find out typical requirements of interface designs,

equipment and possible distribution network reinforcements one can refer to chapter 5 where all interface requirements are summarized.

11..88 CCoonntteennttss ooff tthhee GGuuiiddeebbooookk 1.8.1 This Guidebook comprises of 6 chapters and 12 appendices. The chapters are:

1) Chapter 1: Introduction, provides background to the Guidebook including objectives, basic definitions of terms, list of legal documents and description of the scope.

2) Chapter 2: Process of Getting Connected, discusses the steps involved

from DG plant inception to its operation focusing on activities or procedures for getting connected to the distribution network.

3) Chapter 3: Technical Issues and Requirements for Connection, identifies

and discusses technical issues associated with the connection of a DG plant to the distribution network. For each of the issue discussed, requirements for connection are elaborated.


- 16 –


4) Chapter 4: Planning, Connection and Operation of the DGs, describes planning process involving studies to identify relevant technical issues and their resolutions. The chapter also discusses connection process and its typical operation after successful tests and commissioning.

5) Chapter 5: Interface Design Requirements and Network Reinforcements,

summarises typical interface design requirements and equipment DG plant connection to the distribution network. This chapter also describes typical requirements for distribution network reinforcements.

6) Chapter 6: Glossary, contains definitions of key terms used throughout the

Guidebook. 1.8.2 The appendices are intended to provide useful information and data as well as

details of technical issues mentioned in the chapters including case studies and examples. The appendices are:

1) Appendix A: Summary of TNB Power Systems, provides basic information

on the power systems managed and operated by TNB focusing on its distribution network.

2) Appendix B: Types of DGs, describes several type of distributed generation

available particularly those that have been installed in Malaysia. 3) Appendix C: Data Available and to be Submitted, identifies information

available from TNB at different stages of getting connected and list of data that the Developer should make available to TNB for various purposes of planning the connection.

4) Appendix D: Quality of Supply and Network Performance Standards,

specifies performance standards that TNB has to comply with during planning and operation of the distribution network. The chapter also describes TNB distribution planning and design practices.

5) Appendix E: System Studies Associated with the Connection of DGs,

discusses in detail planning and design studies carried out by TNB to identify technical issues and their resolutions.

6) Appendix F: Protection, Controls and Interlocking Requirements,

provides list of typical protection, controls and interlocking requirements for the DGs including their details.

7) Appendix G: Connection Agreements, provides list of items that should be

included in a typical connection agreement between the DG Developer and the Distributor.


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CChhaapptteerr 22:: PPrroocceessss ffoorr GGeettttiinngg CCoonnnneecctteedd

22..11 SSuummmmaarryy ooff PPrroocceessss 2.1.1 A general process involved for connecting of a DG plant to the distribution

network is shown in Figure 2.1 that comprises of the several phases: 1) Project planning; 2) Exchange of planning information; 3) Project design; 4) Project construction; 5) Project testing and commissioning; and 6) Project Operation. In parallel to the above process, both the Developer and the Distributor would also enter into several negotiations on commercial arrangements including tariff for power exchange and connection charges.

2.1.2 Opportunity for implementing a DG Plant at a particular location usually stems

out from the availability of long-term indigenous fuel or energy resources. The energy resources include biomass from palm oil waste, hydro power and biogas from old waste dumping ground or landfill (see Appendix B). These may include existing captive generation or a co-generation plant within a factory or host site that produces heat and power considering connecting to the local distribution network. There are several reasons for a DG plant or an installation with Embedded Generation (EG) may want to be connected to the local distribution network, including: 1) To sell electricity as an Independent Power Producer (IPP); 2) To sell excess generation, for example, by a cogeneration plant and at the

same time improving overall efficiency; 3) To top-up supply; 4) To use utility supply as standby; 5) A combination of the above purposes. The above purposes are illustrated in Figure 2.2(a) through 2.2(d). Standby supply from the utility on normally open switch is also another possible reason for connection.

2.1.3 After identifying opportunity for generation, the DG Developer should contact the

nearest local or regional TNB offices to enquire on the possibilities for connection to the distribution network. To obtain detailed requirements and cost estimates for connection, the Developer should write to the Distributor by providing basic information (see Appendix C) of the proposed DG plant to enable the Distributor to perform a preliminary system study (see Appendix E) to identify technical requirements for network extensions and its associated estimated costs.


- 18 –

2.1.4 Given cost estimates for connection to the distribution network, the DG Developer could then negotiate and enter into a commercial agreement with the Distributor before carrying out detailed design. The Developer would need to provide detailed information of the DG plant and interface facilities to the Distributor (see Appendix C) for the power system study of the connection (see Appendix E). This will then form the basis for the connection agreement (see Appendix G). At the same time the Developer would in parallel be carrying out detailed design of the DG plant.


1 - Project PlanningDeveloper making commercial & technical

assessments and initial contacts with Distributor on connection possibilities.

2 – Exchange of Information & Preliminary PlanDeveloper & Distributor exchange information so

that Preliminary System Studies on connection can be conducted to determine connection cost.

Figure 2.1: Basic process involved for DG connection to the distribution network

3 – Project DesignDeveloper submit formal application for connection with detailed information on the plant for utility to

carry out Power System Studies, detailed connection requirements & then Developer carrying

detailed design of plant and its connection.

4 – Project ConstructionDeveloper construct plant and Distributor constructs

its connection/reinforcement portions

Commercial Agreement – purchase, standby,

top-up

4 – Project Testing & CommissioningDeveloper & Distributor perform tests and commissioning of the plant and connection

Connection agreement – technical & commercial

Connection OperationManual

5 – OperationDeveloper & Distributor coordinate operation of the

plant with the distribution network


- 19 –

DG

TransmissionGrid


Figure 2.2(a) – 2.2(d): Various power exchange modes for connection 2.1.5 Once commercial agreements including connection agreement are executed, the

DG Developer and the Distributor would enter project construction phase. Prior to operation of the connection, both the DG Developer and Distributor would arrange for testing and commissioning to be carried out. The ‘Connection Operation Manual’ must be established by the DG Developer in consultation with the Distributor as the reference document during the operation of the DG plant.

2.1.6 In the following sections, we will describe in more detail the activities involved in

each step/phase of the process in figure 2.1. The steps for getting connected as described in this Guidebook are generally applied for all DG Plants. In the case of RE Plant, the steps are slightly different because of the commercial arrangements and the DG Developer should refer to TNB for the correct procedure. However, technical requirements for connections for RE Plant are the same as described in this Guidebook.

DistributionNetwork

Load

Pt,Qt

Pg,Qg

(a) Sell all generation

DG

TransmissionGrid

DistributionNetwork

Load

Pt,Qt

Pg,Qg

Heat

Pl,Ql(b) Sell excess generation of

Cogen plant

DG

TransmissionGrid

DistributionNetwork

Load

Pt,Qt

Pd,Qd

Pl,Ql(c) Top up supply from

Distribution network

DG

TransmissionGrid

DistributionNetwork

Load

Pt,Qt

0,0

Pl,Ql

(d) Standby supply

DG

TransmissionGrid

DistributionNetwork

Load

Pt,Qt

Pg,Qg

(a) Sell all generation

DG

TransmissionGrid

DistributionNetwork

Load

Pt,Qt

Pg,Qg

Heat

Pl,Ql(b) Sell excess generation of

Cogen plant

DG

TransmissionGrid

DistributionNetwork

Load

Pt,Qt

Pd,Qd

Pl,Ql(c) Top up supply from


DG

TransmissionGrid

DistributionNetwork

Load

Pt,Qt

0,0

Pl,Ql

(d) Standby supply


- 20 –


22..22 PPrroojjeecctt PPllaannnniinngg 2.2.1 ‘Project Planning’ is a phase initiated by the DG Developer who recognizes the

potential business opportunities of connecting the proposed plant to the distribution network. At this stage, the DG Developer would have identified potential site for the DG plant, energy resources and their long term supplies, types of generating plants (see Appendix B), and cost estimates of the plant. It is also important at this point in time for the DG Developer to understand some basic parameters of the local distribution network including possible connection points, voltage levels and organization of the local utility (see Appendix A).

2.2.2 A DG Developer who intends to sell power to the local utility as an IPP would

first carry out initial assessment of the availability of energy resources for the DG plant and makes preliminary commercial assessment of the DG. At this stage of the feasibility study, the Developer may not know exactly how the DG plant would be connected to the distribution network and this is when the first contact with the utility on the possibility of connection should be initiated. This first contact may discuss both technical and commercial issues.

2.2.3 A cogeneration plant is usually established to provide both heat and power to an

industrial plant or large commercial complex. Such plant or complex may not necessarily be connected to the local distribution network. But since a cogeneration plant consumes fuel efficiently, excess electricity could be sold to the local utility at an attractive tariff. Contact with the district or regional offices of TNB should be the first step to find out on the possibility of connection.

2.2.4 A factory or manufacturing plant having its own captive load may find that the

on-site generation capacity is insufficient to cater for demand requirements due to production growth. The plant owner may find that it is not economical to increase on-site generation capacity instead a more sensible option is to buy top-up power from the local Distributor. In this case an initial enquiry with the local Distributor would enable assessment be made on adequacy of the distribution network for providing the top-up supply.

2.2.5 An installation with on-site generation may find that the available generation

capacity is not sufficient to cater for emergency situations such as loss of generating units. In most cases where there is local distribution network it is more economical to connect the plant to the distribution network that acts as standby rather than adding new generation capacities. Since the Distributor needs to ensure that the network has the required capacity to reserve for the plant emergency requirements, it is important that an enquiry be made with the local distribution offices on possible limitations for standby purposes.

2.2.6 When meeting representatives of the Distributor or TNB District or Regional

officers, it is useful for the DG Developer to prepare basic information of the proposed plant and its possible connection points. The main objective for the DG Developer at this stage would be to: 1) Identify possible connection points; and


- 21 –


2) To obtain and confirm the basic parameters – voltage, circuit capacities, distance to transmission sources, loads in the areas etc. - of the local distribution network.

Distribution engineers at the district or the regional offices must recognize that at this point, the DG Developer requires the above information so that a letter could be submitted to request for estimate of connection cost (see Appendix C).

22..33 EExxcchhaannggee ooff PPllaannnniinngg IInnffoorrmmaattiioonn && PPrreelliimmiinnaarryy SSttuuddyy 2.3.1 A DG Developer should enter into the next phase of the connection process after

confirming with the utility that connection would be technically feasible and that the next important information required is the cost estimates for the connection. Such cost estimate could only be obtained from the Distributor after a preliminary system study is carried out.

2.3.2 To request TNB for the cost estimate of connection, the DG Developer should

officially submit a request letter giving some basic information for the Distributor to carry out preliminary system study (see Appendix C). After receiving the request letter and basic information on the proposed DG, the Distributor would be in a position to carry out a preliminary system study in accordance with procedures as described in Appendix E.

2.3.3 At this preliminary stage, it is sufficient for DG Developer to provide the following

basic data to the Distributor with the request letter: 1) Number of generating units proposed and capacities in kVA; 2) Fuel resource; and 3) Physical location of the plant. A location map indicating the plant site and nearest existing distribution medium voltage network facilities should also be submitted with the request letter.

2.3.4 On receipt of the request letter, the Distributor should carry out a preliminary

system study so that major equipment to be added to the network could be identified and their costs estimated. Typically the Distributor would carry out a preliminary system study by assuming certain parameters for the plant and applying procedures as described in Appendix E. The analysis carried out include: 1) Voltage performance; 2) Network adequacy; 3) Short-circuit calculations; and 4) Losses.

2.3.5 The results of the preliminary system study would enable the following questions

be answered: a) The feasibility of connection; b) Point of connection; c) Major equipment required for connection; and d) Estimated cost of connection. The preliminary system study would also identify technical issues that may need to be addressed further if the DG plant connection is to proceed to next stage. In


- 22 –


particular the Distributor would inform the DG Developer of issues that may need to be addressed during the plant design stage.

2.3.6 To ensure transparency in the preliminary planning process, the Distributor is obliged to provide a summary of the preliminary study report to the DG Developer.

22..44 PPrroojjeecctt DDeessiiggnn 2.4.1 With the cost estimate for connection provided by the Distributor, the DG

Developer would be able make further assessment on the commercial viability of the DG plant and its connection to the distribution network. If the DG Developer decides to proceed with the DG plant development, the Project Design phase should begin. In parallel to the project design, it is usual for the DG Developer to also start negotiations on commercial terms and agreements with the Distributor.

2.4.2 The DG Developer at the project design phase would normally employ services

of consultants to carry out detailed design and establish specifications for procurements and installation. As soon as details of plant design and equipment are available, the DG Developer should submit a formal application for connection to the Distributor making reference to the earlier preliminary system study and highlighting major changes to plant basic parameters. Formal application form for connection and details of the data to be submitted to the Distributor are given in Appendix C.

2.4.3 On receipt of formal application for connection, the Distributor should examine

the information submitted by the DG Developer and should ensure sufficient data are provided to perform detailed power system study. At this stage, both the DG Developer and the Distributor may organize several meetings and discussions to exchange and confirm information.

2.4.4 The main objective of the power system study to be carried out by the

Distributor at this stage is to ensure that the connection of the DG Plant will not deteriorate the quality of supply and power that is being provided to the existing customers in the vicinity of the DG plant. If the connection affects the quality of supply, the Distributor is required in accordance with the prevailing codes and regulations to apply mitigation measures and the cost of which would have to be borne by the DG Developer. It is therefore vital that the Distributor performs the power system study by taking into consideration all factors with valid assumptions and that the full study report should be made available to all stakeholders including the DG Developer.

2.4.5 Study report of the power system study should contain sufficient information on

connection requirements to be used by the DG Developer to establish specifications for procurement and implementation of the connection. It is important that the study report provide a list of connection interface requirements with sufficient details of parameters to be applied.


- 23 –


2.4.6 Based on the recommendations of the study report, the DG Developer should proceed with the specifications and procurements of the DG plant and the associated interface requirements.

22..55 PPrroojjeecctt CCoonnssttrruuccttiioonn 2.5.1 Project construction phase would normally comprise of the following activities:

a) Detailed design; b) Preparation of specifications; c) Bidding; d) Procurement; and e) Construction. The construction of the DG plant can be divided into two parts: plant installation; and interface and connection to the distribution network. Construction of the plant is completely the responsibility of the DG Developer.

2.5.2 With respect to the construction of the interface and connection to the

distribution network, two options can normally used: 1) Constructed by the DG Developer under the supervision of the Distributor; or 2) Constructed by the Distributor. This part of the network would be operated and maintained by the Distributor.

22..66 PPrroojjeecctt TTeessttiinngg aanndd CCoommmmiissssiioonniinngg 2.6.1 Prior to the commissioning of the DG Plant and its parallel operation with the

distribution network, the DG Developer would coordinate with the Distributor to identify and list of tests and performance criteria, test procedure and approval.

2.6.2 The ‘Connection Operation Manual’ to be established by the DG Developer in

consultation with the Distributor must be updated based on the findings and results of the commissioning tests.

22..77 DDGG OOppeerraattiioonn 2.7.1 When a DG Plant begins commercial operation and in parallel with the

distribution network, the provisions of electricity rules and associated codes and guidelines govern the operational obligations of both the DG Operator and the Distributor. The details of the operation procedure will be spelled out in the ‘Connection Operation Manual’ (see Appendix G).

2.7.2 Among others, the ‘Connection Operation Manual’ includes the following items:

a) Data to be exchanged between DG Operator and Distributor; b) Operational planning and scheduling procedure; c) Dispatching and control procedure; d) Fault and defect reporting; e) Loss of mains and restoration procedure; and f) Joint operation committee.


- 24 –


CChhaapptteerr 33:: TTeecchhnniiccaall IIssssuueess aanndd RReeqquuiirreemmeennttss ffoorr CCoonnnneeccttiioonn

33..11 RReessppoonnssiibbiilliittiieess ooff tthhee DDiissttrriibbuuttoorrss ttoo CCuussttoommeerrss aanndd tthhee DDGGss 3.1.1 TNB and Other Distributors regulated businesses are obliged under their

licences issued by the Energy Commission (EC) to maintain a standard of supply and services to their customers. These requirements are usually specified in the conditions of the licence issued by the regulator to the utility. Based on the provisions of the licence conditions and to ensure that the requirements are complied with, TNB has established ‘Quality of Supply Standards’ as given in Appendix D.

3.1.2 TNB is responsible for ensuring that the requirements or provisions of the Quality

of Supply Standards are complied with at all times. TNB would require imposing some minimum requirements for any User connections such as a DG to ensure that the Quality of Supply Standards is maintained.

3.1.3 The objectives of this chapter are:

To summarise the quality of supply standards that TNB has to comply with; To discuss all possible technical issues that may arise with the connection of

a DG to a distribution network that could affect quality of supply; and Where appropriate, to suggest mitigations to alleviate the issues.

33..22 QQuuaalliittyy ooff SSuuppppllyy RReeqquuiirreemmeennttss 3.2.1 The quality of supply that a Distributor like TNB must comply with comprises of

several aspects whose requirements are summarized in the following paragraphs.

3.2.2 Under normal operating condition, the steady-state voltage at a customer’s

connection/interface points must remain within the following ranges (see table 3.1).

Table 3.1: Steady-state voltage limit, normal condition

No Nominal voltage (kV)

Limits

1 33 ± 5 % 2 22 ± 5 % 3 11 ± 5 % 4 0.415 + 5% and − 10%


- 25 –


3.2.3 Under contingency operating condition, the voltage at a customer’s connection/interface points should remain within the following ranges (see table 3.2).

Table 3.2: Steady-state voltage limit, contingency condition

No Nominal voltage (kV)

Limits

1 33 ± 10 % 2 22 ± 10 % 3 11 ± 10 % 4 0.415 ± 10 %

3.2.4 For a distribution network, a normal operating condition is when all major

elements including lines, cables and transformers are operating. However, the network is said to be in contingency operating condition when any one or more of the major elements are not operating due to forced or scheduled outages.

3.2.5 With respect to thermal capacity limits of transformers, switchgears, overhead

lines and cables, TNB has set a criterion that under both normal and contingency operating condition these equipments must not operate beyond their thermal limits.

3.2.6 The maximum three-phase short-circuit current allowed in TNB network are

given in table 3.3. When the short-circuit level at any point in the network exceeds 90% of the limits in table 3.3, actions must taken to circumvent the situation.

Table 3.3: Maximum 3-phase fault currents

No Nominal Voltage (kV)

Maximum 3-phase Fault Current (kA), duration (s)

1 33 25, 3s 2 22 25, 3s 3 11 20, 3s 4 0.415 31.5, 3s

3.2.7 The system frequency is maintained by TNB at 50Hz ±1%. Under emergency

situation and when the frequency drops below 49.5Hz, TNB may shed some loads through the under-frequency load-shedding scheme.


- 26 –


3.2.8 With respect to supply reliability, TNB is required to plan and design the medium voltage network that will minimize the System Average Interruption Duration Index (SAIDI). For actual network planning and design TNB applies Supply Security Criteria or Contingency Criteria as given in table 3.4.

Table 3.4: Security of supply criteria for medium and low voltage networks

No Type of network Supply security requirements 1 Urban/Sub-Urban

Medium Voltage Distribution Feeders

• In the event of a feeder outage, the load of the feeder can be transferred to adjacent feeders by manual or supervisory network reconfiguration.

• In the event of a failure of a main intake sub-station (PPU or PMU) transformer in the supply zone: all of the loads can be transferred to the

other transformer in the main-intake sub-station; or

All of the loads can be transferred to other main intake sub-station transformers within the supply zone or other nearby adjacent supply zones.

2 Rural Medium Voltage Distribution Feeders (<1 MVA)

For rural areas of total loads less than 1 MVA, the contingency criteria for these feeders are not applicable. However, where reasonably (economically) applicable, interconnections between feeders shall be provided.

3 Low Voltage Distribution Networks

Low voltage distribution service cables to users are planned and operated as radial circuits.


- 27 –


3.2.9 TNB also specifies power quality compatibility requirements and guidelines to be complied with as given in table 3.5.

Table 3.5 - TNB Power Quality Compatibility Standards and Guidelines

No Quality of power

variation

Measurement Maximum permissible value for all sources

Standards/ Guidelines

1 Distortion Total Harmonic Distortion Voltage (THDV) %

5% at 415/240 Volts 4% at 11 and 22 kV 3 % at 33 kV

Engineering RecommendationG5/4

2 Flicker Pst, Plt

Pst, 1.0, Plt 0.8 (at 132 kV and below)

Pst, 0.8, Plt 0.6 (Above 132 kV)

Engineering Recommendation P28

3 Momentary Voltage Change Limits

V % 1 % - series voltage change that may lead to flickering problems

3%- single voltage change due to switching ON or OFF of any loads

Engineering RecommendationP28

4 Voltage Unbalance

Negative Phase Sequence Voltage %

2 % for 1 minute duration Engineering Recommendation P24-1984 P29-1990

5 Voltage sag

% Remaining Voltage

50 % Sag (up to 200 ms) 70 % Sag (up to 500 ms) 80 % Sag (up to 1000 ms)

SEMI F47

3.2.9 Details of the quality of supply standards are discussed in Appendix D.


- 28 –


33..33 TTeecchhnniiccaall IIssssuueess 3.3.1 Distribution systems in Peninsular Malaysia have traditionally been designed

with a single source from a transmission substation. Although the distribution network may be connected to another transmission source, the two sources are not normally operated in parallel. At the transmission substation, voltage transformation from transmission to distribution is established (e.g. 132/11kV, 132/33kV, 275/33kV etc.). Voltage control is achieved using on-load tap changer with the voltage on the distribution bus being regulated (using automatic voltage regulator or AVR) to a specified range. Only the voltage at the busbar connected to the transformer LV winding at the transmission substation is maintained more or less to a constant value by the transformer AVR. The AVR is not capable of maintaining the voltages of other nodes or substations. Therefore, to provide further voltage regulation, reactive sources such as shunt capacitors are located at strategic points in the system.

3.3.2 Distribution systems, being generally passive in nature, are not normally

designed to accommodate generators. The connection of a DG unit to the distribution system would seem to provide benefits because it serves the loads from local source and thereby reducing transmission, substation and feeder loading. However, there are several technical issues that must be recognized and addressed before a DG could be connected to the distribution network.

3.3.3 The technical issues are discussed in details in the following sections. Where

necessary more detail treatment of the subjects will be referred to the relevant appendices.

33..44 VVoollttaaggee CCoonnttrroollss aanndd RReegguullaattiioonnss 3.4.1 Other than the obligations to control voltage within limits, voltage control

provided by the DG do bring some advantages such as: improving voltage profile across the distribution network; improving system losses; improving system load flows; avoiding potential system collapse; and in certain circumstances, voltage control can aid starting of large motors.

3.4.2 The power factor at the main intake substations (PMU/PPU) is typically

maintained at 0.9. The Distributor is under an obligation to maintain PMU/PPU’s power factor to not less than 0.9.

3.4.3 Normally, voltage control in a distribution system is provided by on-load tap

changing transformers (in-service transformers tap-changing) at the transmission substations or large distribution substations. In addition to this, switched and fixed capacitor banks are employed at strategic locations within the distribution system. Boosters are seldom used now because of their high costs but have been employed on the medium voltage level. In the LV system, voltage


- 29 –

regulators are employed but now being replaced by switched and fixed capacitors. Figure 3.1 illustrates different types of voltage control devices employed in the distribution network.

3.4.4 More expensive means of voltage control is possible with modern FACTS

(Flexible AC Transmission Systems) devices. One example of such a device is Static VAr Compensators (SVC). These devices are often used within transmission systems but costs of these devices are high.

132kV

33kV

11kV

OLTC

OLTC

FixedShuntCap

SwitchedShuntCap

NLTC

Pole-topShuntCap

11kVBooster

TransmissionNetwork

0.415kVLV

Network

MVNetwork

33kV

Figure 3.1: Voltage control devices in a distribution network

3.4.5 A synchronous generator embedded in the distribution network would normally be equipped with an automatic voltage regulator (AVR) capable of controlling the voltage or the VAr output at the generator terminal. This is performed by the AVR through regulating DC excitation current to the generator field circuit.

3.4.6 Although the AVR is usually available, it has been the DG and the Distribution

System Operator operational practice to keep the generating unit on ‘power factor control’. Power factor control means that the reactive power output of the generating unit is maintained in proportion to the MW output such that the power factor would remain constant regardless of the terminal voltage (see Figure 3.2). When on power factor control, the generating unit does not regulate voltage, unless it is above the AVR set limits for voltage. The reasons for running a generating unit on power factor control are:



- 30 –

1) Commercially the DG is treated as a negative load and penalties can be imposed for poor power factors or leading power factors in relative to real power export.

2) It is sometime advantageous for a Distribution System Operator to match the generating unit’s power factor to the demand power factor. This is normally in the region of 0.95. Operating the unit this way would ensure that the power factor of the flow from the Grid to the distribution system is kept more or less constant.

3) Where the DG whose output is not constant is connected close to a Grid Transformer it would have less interaction with the Transformer Automatic Voltage Control if the unit is operated on power factor control.

However, using power factor control may result in system voltages breaching the limits particularly during light load condition.

S

Terminal Voltage

MVAR

MW

0.95 pf

Example of power factorcontrol line

Example of voltage control line

Example of MVAR control line

Figure 3.2: Generator reactive capability limit and controls. 3.4.7 To ensure proper voltage and VAr control within the distribution system, DGs will

be required to have the capability of both voltage control and power factor control. Figure 3.2 also shows examples of typical reactive power controls for a DG. The reactive capability of typical generator is normally between 0.85 lagging to 0.95 leading at full load.

3.4.8 The choice of control modes will be subject to the ‘Preliminary System Study’ to

be carried out by TNB. It is useful to note that the advantages and disadvantages of the various controls as in table 3.6.

3.4.9 The discussions on Voltage Control above have been focussed on the

Generation Unit because a majority of Generating Units are directly connected to



- 31 –


the Distribution System. There are a number of Generating Units that are embedded within their site network, such as a Co-Generation plant. In these cases, the power factor or voltage control requirements will refer to the Connection Point to the Distributor’s network.

Table 3,6: Advantages and disadvantages of three VAr controls

Controls Advantages Disadvantages Power Factor Control

1) Fix and forget similar to demand

2) Prevents commercial penalty for ‘poor’ power factors

3) Less interaction with Transformer voltage controllers

4) Can be used if more that one generator is connected to the same bus-bar.

1) May cause large voltage variations between the extremes of light load to peak load conditions

Voltage Control 1) Can control voltage variations up to the limit of generator capability.

1) May cause large voltage variations between extremes of generating full load to generator tripping

2) Can cause excitation system hunting if more than one generator controls the same busbar voltage

VAr Control 1) Normally used in large distribution systems, e.g. where voltage control is ineffective.

2) Useful if the Var control is dispatched.

1) VAr contributions can only be relied on for reliable generation.

2) Excitation droop settings would need to be set for Var sharing between multiple generators.


- 32 –


33..55 FFaauulltt LLeevveellss 3.5.1 Synchronous generators contribute fault currents in response to network faults.

Fault currents are necessary to operate protection systems especially when discriminating between normal operating current and currents produced as a result of a fault. Fault currents are also required to enable system voltages to recover following a fault clearance. Similarly, fault current contributions are essential to reduce transient voltage drops, for example during starting of large motors

3.5.2 When a generator is connected to the distribution network, the prospective short

circuit or fault level of the network will increase because of the potential fault current contribution. This rise of prospective fault level will be limited by the system capability to withstand a potential fault current. This limit is the equipment capability such as switchgear and cables. If the fault level at a node in the network increases to more than 90% of the equipment short circuit rating than measures must be taken to mitigate the situation. The safety margin of 10% takes into account the tolerance allowed for the network data accuracy especially the existence of induction motors in the system. Under no circumstances should the prospective short circuit current be allowed to exceed the equipment rating

3.5.3 The common utility practice is to determine short circuit currents in the network

on two types of faults, namely: 1) 3-phase fault; and 2) 1-phase to ground (or earth) fault. Figure 3.3 shows the common terms used in defining a typical generator fault current contribution.

Figure 3.3: Fault currents contribution from a generator

PeakMake

PeakBreak

Protection time Contact separation

FaultClearance

FaultCurrentkA

Time (ms)

50 100 150 200

Phase current

DC offset


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3.5.4 Generator fault current contributions are calculated using parameters supplied for the generator. The calculated fault currents on both types of faults must then be checked against the following fault duties of ratings of circuit breakers: 1) Breaking Capacity (MVA/kA) - The capacity that a circuit-breaker is capable

of breaking at a stated recovery voltage and re-striking voltage. Recovery voltage is the normal frequency voltage that appears across the breaker poles after final arc extinction and re-striking voltage is the voltage that appears across the contacts at the instant of arc extinction. This is normally measured as an RMS value at the time when the circuit breaker contacts are required to open as indicated in Figure 3.3.

2) Making Capacity (MVA) (normally 2.5 times the Breaking Capacity, defined as the asymmetrical peak at 10ms) - The capability of the circuit-breaker when closing on a standing fault.

3) Short-Time Rating (kA, rated time) - The capability of the circuit-breaker or cables to carry the specified maximum fault current for a given period of time normally 3 seconds.

3.5.5 The limit on equipment fault level capability is normally the main reason for

difficulties in connecting a generator. Equipment may need to be replaced to enable generators to be connected. Replacing equipment in order to raise fault level capabilities can be extensive over the network and the cost of replacing equipment can be very high. However, there are a number of alternative mitigations to reduce the generator contribution to the system possible namely: 1) Increase generator impedance – The generator impedance is normally limited

by the generator design. Changing generator impedance could mean a non-standard design which is normally more expensive than a standard generator.

2) Use of in-line reactors – Reactors introduce impedance between the generator and the network, thus assist in reducing the generator fault current contribution. However, the disadvantages of using reactors are that losses are increased and may also cause undesirable voltage reduction at the connection point. The overall VAr capability of the generator is also decreased because of the VAr consumed by the reactor. Generator stability may be affected by too high impedance.

3) Use of in-line transformers – Using a transformer reduces the disadvantages compared to the use of a reactor, however, the cost of a transformer is much higher that the cost of a reactor. Transformers are also used for power quality reasons.

4) Network Splitting – Network splitting involves keeping certain parts of the circuits normally open to reduce fault levels. Although very effective, but it may mean less system security and increased operational effort. Installing automatic switching systems, such as active management system, could make this option viable.

5) Fault limiters – Is limiters are available in the market. Although effective, it does have safety concerns mainly because it is an explosive device and concern about repeatability of operation. Research is still being carried out using super-conductor technologies which would address these concerns.


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6) Connection to a higher voltage - Higher voltage system have a higher fault level capability. However, equipment costs would be much higher.

7) Generation constraints – Some fault levels problems may be only evident during certain network configuration, for example during an outage. It may be acceptable for generation to be prevented from running during these periods. This option should only be considered if the periods of constraints are very short.


33..66 NNeettwwoorrkk//FFeeeeddeerr CCaappaacciittyy aanndd SSeeccuurriittyy AAsssseessssmmeennttss 3.6.1 Security assessment will be carried out for any demand or DG connections to

the distribution network in accordance with security requirement in table 3.4. This is based on (N-1) contingency.

3.6.2 There is a distinct difference on how network capacity and security is assessed

when connecting demand or generator. Where a firm connection for demand cannot be guaranteed, then the network would be reinforced accordingly. However, for generation connections, the developer may have a choice of a firm or non-firm connection depending on the reinforcement costs needed to accommodate the generator capacity (see Figure 3.4).

10MVA10MVA

5MVA 5MVA 2MVA

10MVA10MVA

Figure 3.4: Demand and generator connections – firm and non-firm 3.6.3 For both demand and generator connections, normal and contingency

conditions will be considered. Demand Connections are assessed using (N-1) contingency criteria. This is a deterministic contingency criterion. As shown in

2MVA load cannot be addedwithout reinforcement

DG DG

12MVA 10MVA

Choice of firm or non-firm connection.12MVA DG connected but

2MVA is non-firm

Demand Connection Generator Connection


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Figure 3.4, if the future total demand is greater than 10MVA, the network will need to be reinforced to ensure that firm demand is guaranteed on the outage of one circuit. Network reinforcements for demand needs to take into account both current and future demand growth.

3.6.4 Generation connections are treated differently. Any reinforcement considered

will only be for the generator capacity to be connected without any consideration for future generator connections. As illustrated in Figure 3.4, a 10MVA DG will be guaranteed access based on (N-1) criteria. However, if a 12MVA generator is to be connected using the same network only 10MVA will be guaranteed, i.e. firm. For the remaining 2MVA, the developer could have a number of options.

3.6.5 If a firm 12MVA connection is preferred, then network reinforcements will be

required. In the above example either a third 10MVA transformer is installed or the two 10MVA transformers are replaced by two 12MVA transformers to fulfil the (N-1) criteria.

3.6.6 Another option is not to carry out any reinforcements, in which case, 12MVA can

be exported during normal network conditions, i.e. no circuit outages. However, during one circuit planned outage, the generator would need to be constrained to 10MVA. This means that 10MVA will be firm whilst the remaining 2MVA will be a non-firm output.

3.6.7 The planning criteria could also allow for short term overload rating over the

equipment continuous rating. Using this short term rating of 120% for example and allowing for a (N-1) contingency, a generator rated up to 12MVA could be allowed to be connected. For an unplanned outage of one circuit, this particular generator would need to reduce its output from 12MVA to 10MVA over the period allowed for short time overload rating of the circuit. This could be from milliseconds to minutes depending on the plant item being overloaded.

3.6.8 If reinforcements are not carried out, the Developer will take the risk of the

generator output being constrained during both planned and unplanned outages. TNB would co-operate with the developer in understanding these risks. To reduce these risks, the developer could schedule his plant outages to coincide with TNB’s planned network outages.

3.6.9 There are two main options available for constraining generation given a non-

firm connection. Generally, if there is an allowable period before the generator is needed to be constrained, then a dispatch instruction is used. This type of constraint instruction is used for planned outages or short time rating constraint as described above. However, if an immediate constraint is required, an automatic intertripping and/or fast generator de-loading system would be required. This is normally used for unplanned network outages. It should be noted that the complexity of intertripping systems depends on the complexity of the network to be protected.

3.6.10 The above is based on a very simplistic configuration. In an actual distribution

network, there are many more parameters to be considered such as network


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operational conditions, level of demand in the area, overload capability of network components and other generation outputs in the area. Demands and generating capacities can often be used to optimise on the re-enforcements needed.

3.6.11 For example, where practicable, circuit capability for firm generation output

should be assessed in conjunction with demand. In the example above in Figure 3.5. A generator of up to 12MVA capacity could be considered for a firm connection whereas if demand is not taken into consideration, a generator of only 10MVA would be considered as firm. When considering reinforcements for future demand increase, local generator outputs should also be considered if appropriate. The methodology of assessing generator contribution is being used in the UK in the P2/6 Planning standards. This standard is still undergoing public consultation.

10MVA10MVA

DG

12MVA

2MVA

Figure 3.5: Taking consideration of load and firm generation 3.6.12 Active network on-line monitoring and automatic control will reduce the risk of

generators being constrained. Reinforcements could be deferred through knowledge of minute-to-minute demand loadings and generator outputs.

3.6.13 A generator will tend to unload the feeder between it and the main intake

substation, and will have no effect between the generator and the end of the feeder. This will depend on the generator output in relation to the existing demand power flow. Generator output higher than the existing demand current flow and the use of shunt reactor may overload segments of the feeder between the generator and the main intake substation as illustrated in Figures 3.6a) and (b). Feeder loading situation must also be assessed to cover future years.



- 37 –

3.6.14 Also in the future, network assessment could adopt a more probabilistic methodology which should result in reduction in reinforcements.

DG

S

Main IntakeFeeder 1

Feeder 2

Feeder 3

Feeder 3

Feeder 3

Figure 3.6(a): Feeder without DG

DG

S

2.2MW

Reactor

Main Intake

DG Plant

Feeder 1

Feeder 2

Feeder 3

Feeder 3

Feeder 3

Figure 3.6(b): Feeder segments overload with DG 3.6.15 Distribution system would normally have interconnecting feeders with open

points. Under contingency or maintenance when one section is on outage switching operation would be carried out to restore supply. Adequacy of circuit



- 38 –


capacities must then be assessed under both normal and contingency situations.

33..77 SSuuppppllyy QQuuaalliittyy –– RReelliiaabbiilliittyy aanndd PPoowweerr QQuuaalliittyy 3.7.1 Supply quality covers two aspects:

1) Reliability of supply – customers expect continuity of electricity supply 2) Power quality – the shape of voltage waveform remains sinusoidal and

without distortion. Supply reliability is measured by indices like SAIFI (System Average Interruption Frequency Index) and SAIDI (System Average Interruption Duration Index). Power quality is measured using criteria as shown in table 3.5.

3.7.2 A DG can improve the reliability of supply to the distribution network customers

by providing network support. For example, if the DG is allowed islanding operation rather than being isolated on loss of mains.

3.7.3 If the DG is to be isolated on loss of mains, the DG does not have impact on

reliability and figures for SAIDI and SAIFI remain the same as without the DG. It could however make it worst since new components are added to the network including lines, switches and transformers that may fail and disconnect the feeder. If the DG is allowed to operate on islanded mode to supply total or some of the feeder loads, then reliability would improve since sustained failure of components between the feeder source and the DG would enable the DG to supply some loads that otherwise have to wait until repair is done.

3.7.4 The issues on power quality such as voltage sags, over voltages are discussed

elsewhere in this Chapter. Voltage sags are discussed in Section 3.4 – Voltage Controls and Regulation and Section 3.5 – Fault Levels. Over voltages are discussed in Section 3.12.

3.7.5 Harmonics can generally be a problem when using semiconductor devices such

as converters within the network. Very high harmonic levels are associated with the use of converters in smelting works. Careful monitoring of harmonic level necessary where a number of these devices are used in the network. Generators and transformers can dissipate harmonics currents; however, it will cause over-heating. Information on Total Harmonic Distortions (THD) is available from the Distributor on request.

3.7.6 Flicker is not currently a problem with the levels of generation connected to

distribution system. However, with increasing generation connections and different generation technology, interactions between generation and incorrect control settings could cause flicker. Power System Stabilizers (PSS) installed in Generator excitation systems can be used to control flicker. It should be noted that studies will be required to obtain the correct settings for the PSS.


- 39 –


33..88 PPrrootteeccttiioonn aanndd CCoonnttrroollss

33..88..11 GGeenneerraall 3.8.1.1 Protection systems are essential for both the network and the generator to

ensure safe operation. Network and generator protection systems do interact and will need to be designed to co-ordinate with each other. TNB is responsible for design and operation of the network systems, whilst the Developer is responsible for design and operation of the Generator systems. At a stage in the generation project, an interchange of information between the developer and the Distribution Operator is essential to enable each system is designed to be coordinated.

3.8.1.2 The design of the network protection systems is based on TNB’s Protection

and Control Code of Practice. All equipment used in TNB’s is approved by TNB. The use of approvals and Code of Practice is needed to ensure design and plant consistency across the network.

3.8.1.3 Generator connections and generator protection systems should be designed

to a prudent utility practice and conform to current safety and regulatory standards. The following should also be taken into account when designing generator protection systems. Technical specifications for interface equipment – Protection systems that

interface with the network systems, such as any differential protection systems, will need to use approved TNB specification to ensure compatibility and consistency of performance.

Fault clearance time for generator faults – There are a number of faults within the generator systems that could affect the stability of Distribution Networks. It may then be necessary for the network operator to define certain protection operation performance. Normally, this is limited to protection operation and fault clearance times.

Unit protection for connection cables – It has been the practice of the Distribution Network Operator to equip the connection cable with unit protection. This was found to be necessary to protect the network against incorrect co-ordination afforded by slow over-current feeder protection. Where appropriate and economical, the Distribution Network operator will consider directional current protection.

Generator Protection System Minimum requirements - Appendix 5 include a typical protection system diagram and the minimum requirements for a generator protection system.

Connection point minimum requirements – Similarly Appendix 5 shows a typical connection minimum requirements including loss-of-mains protection. Specific minimum requirements may include single generator connection and top-up/standby type connections.

Other requirements - Pole slipping protection could self-protected generators from system instability and may be required as identified by stability studies.

NVD protections – Subject to safety and regulatory considerations, NVD protection could be used on systems where it could be inadvertently un-earthed for a very short time.


- 40 –


Distribution Network Back-up fault clearance - Network backup fault clearance can take up to a maximum of 1.2 seconds at the source. Developers will need to take this into account when designing protection systems.

33..88..22 SShhoorrtt tteerrmm OOccccaassiioonnaall PPaarraalllleell OOppeerraattiioonn 3.8.2.1 Consideration for reduction in requirements will be given for generators

requiring short time parallel operation. These are generator systems which are normally operated in islands with their demand, but require standby supplies from the Distribution Network during generator outages.

3.8.2.2 The islanded system is only synchronized to the Distribution Network before

the generator supporting the island is taken out of service. Provided that the generator is taken off-line as soon as the system is synchronized, certain protection requirements such as loss-of-mains may be exempted. The following systems may be required to be implemented: Automatic change over between generator circuit breaker and Network

connection circuit breaker such as make before break systems. Controlled short-term paralleling for test and commissioning Complete protection system may not be required Use of timers to limit time for parallel operation Site protection systems will need to be configured when connected to the

Distribution Network due to the change in fault levels for example.

33..88..33 LLoossss ooff MMaaiinnss 3.8.3.1 Occasionally, due to network faults, parts of networks containing embedded

generation or DG may be inadvertently islanded. Depending on the demand requirements and the generator performance, the DG could remain in operation, thus supporting the island.

3.8.3.2 Distributors are obliged to maintain a safe system and may be liable for

damages if generator without proper control is allowed to supply the regulated network and breach the regulatory frequency and voltage limits. Protection systems and earthing systems are also not designed for inadvertent generator island systems. For these reasons, it is essential that generator that could potentially support islanded systems is tripped when the condition arise using loss-of-mains protection systems.

3.8.3.3 The use of auto-reclosers also makes it necessary for the loss-of-mains

protection to trip the relevant generators before the auto-reclose recloses. Loss-of-mains protection is usually installed at the point of connection to the Distribution Network. This arrangement would allow a generator to be islanded within its own private network if required. A number of loss-of-mains systems are possible depending on required operation time, network configuration, demand and generator output.


- 41 –

3.8.3.4 ROCOF/Vector Shift -The system works on the principle of fast frequency change and waveform shift characterised at the instant when systems are islanded. However, these systems are prone to nuisance tripping because the relay can detect overall Grid system disturbance. Generally it will trip more that necessary, depending on the settings. It is the more cost effective system compared to other systems. A number of issues have historically been identified with these systems namely: Settings - finding suitable settings may be difficult. It may be necessary to

estimate initial settings and monitor its behaviour. Simulating credible system disturbances can assist be used to estimate settings.

Demand to Generation balance – There may be cases where demand almost equals generation output and the rate of change of frequency or vector shift is not sufficient to cause operation.

Testing - On site operational testing will be a problem. System monitoring is an option.

3.8.3.5 Intertripping - Intertripping is an alternative to ROCOF/Vector Shift relays. The

system is more reliable but can be expensive for an extensive Distribution Network system. To limit the complexity of the system, the assessment is based on monitoring circuit breakers up to the point where generator will not be able to sustain system load. In the example shown in Figure 3.7, the intertrip is set between the two breakers where the generator can just sustain the network demand. The principle depends on the generator tripping on the generator over-current whenever systems islanded contain more demand than the generator capability. The use of intertripping in conjunction with auto-reclosers is described in detail below.


2MW

2MW 2MW

DG2MW

A B C D

Intertripping may only be required between breakers C and D

Figure 3.7: Example intertripping on loss of mains


- 42 –


3.8.3.6 Generator overload in combination with Over/Under Voltage and Over/Under Frequency - As described above, if the potential islanding configuration has demand greater than the generator overload setting, an over-current protection relay could be an effective loss-of-mains protection. However, in the assessment, consideration must be taken during light load conditions where the condition may not be true and other loss-of-mains of protection as described above needs to be installed.

3.8.3.7 Over/Under Voltage and Over/Under frequency - Over/Under Voltage and

Over and Under Frequency protection systems is the minimum requirement at the connection point. These protection relays normally take longer to operate than those described above and thus may not be suitable for use with auto-reclosers

33..88..44 AAuuttoo--rreecclloossiinngg 3.8.4.1 Auto-reclosing are used on overhead lines within Distribution Networks. The

system is used to reclose lines that are tripped by self-clearing faults, such as tree branches touching the lines.

3.8.4.2 Auto reclosing lines that have generators connected within the system could

result in out of phase closing. The impact of connecting out-of-phase systems could be destructive and could lead to: Extensive Generator Damage; Network Circuit Breaker Damage; and Network Voltage Sag due to the high currents caused when connecting out-

of-phase systems. Depending on the phase angle at connection, twice fault currents can potentially be generated if the voltage at synchronization is totally opposite in phase and amplitude.

3.8.4.3 Reliable and fast loss-of-mains tripping will be required where reclosers are

used in systems that can be potentially islanded for a short period. Normally, the use of intertripping for loss-of-mains would provide the reliability and speed of operation. The use of over-current relays for loss-of-mains may also be suitable, provided the speed of over-current operation is faster than the auto-reclosing time.

33..88..55 IIssllaannddeedd OOppeerraattiioonn 3.8.5.1 Islanding within the Distribution system has not been implemented generally.

However, there are isolated areas which are supplied by systems which are islanded or capable of being islanded. Generally these would be remote systems where interconnection to the main distribution system is prohibitively expensive. Generator capabilities and its performance within these islanded systems are crucial and need to be controlled. Two main control systems required are voltage and frequency control.


- 43 –


3.8.5.2 Note that it is Distributor’s responsibility within the Electricity Regulations to maintain a safe system, thus the need for the Distributor to be responsible for generator control. As such, the technical and performance requirements will need to be specified. This will be an additional cost to the DG Developer. An incentive within the DG ancillary service could provide the needed financial support to provide the capabilities.

3.8.5.3 The performance requirements will require sophisticated generator and

network control to match generation with demand. Some of the capabilities for generators and the Distribution System would include: 1) Isochronous operation

This type of operation is normally suitable for smaller machines or a single machine supplying a system where the demand is less than the generator output. Isochronous control used in the generator will maintain frequency by increasing or reducing its output. There is a need to maintain a margin between the generator output and the demand. The frequency control can be coarse and may exceed regulatory limits transiently. Load shedding schemes can be used to supplement the frequency control.

2) Governor droop control This is the principle used in Transmission Grid system for controlling frequency. Governor droop control is used for larger systems containing multiple generators. Droop control will allow generators to share their outputs proportionally when maintaining frequency. Some form of fast frequency response systems may be required depending on the nature of the demand are required for fine control. Droop settings will be dependent on the system and its demand.

3) Demand load shedding/frequency tripping systems To supplement generator control, demand load shedding can be used for controlling frequency. This system is normally used as an emergency measure. Demand will need to be prioritised for tripping based on acceptable levels of frequency deviation.

4) Network voltage control Voltage profiles can be controlled by the generator excitation systems and Transformer AVRs. Where multiple generators are present within the same system; care is needed in setting the excitation controls to prevent system interactions. Voltage profiles do change when systems are running islanded due to the changing system flows. Transformer AVR controls and generator excitation system controls would need to be switched to enable them to operate within an islanded system. Transformer AVRs operation in particular will be affected by reverse power flows.

5) Seamless Islanding/Black Start Seamless Islanding would mean that a customer would not see any supply interruptions. In order to facilitate seamless islanding, all generators required to support the island would need to automatically switch to its islanding capabilities described above. These systems may be complex and could be unnecessarily expensive. A manual system could be implemented where generators would need to be equipped with Black Start capabilities. The Islanded Distribution systems are initially allowed to be de-energised and the systems are then re-energized by matching generator output with demand at


- 44 –


all stages of restoration. The length of supply interruptions would depend on the speed of restoration of Black Start cells.

6) Network re-synchronising control and locations Restoration of sub-islanded systems to the main networks will require synchronizing points to be identified within the system. Voltage and frequency control between multiple generators would need to be coordinated so that voltage and phase angles could be matched to allow synchronizing.

7) Loss-of-mains protection This protection is described in Section 3.8.3. Islanded systems will need to be separated from the main Distribution System by loss-of-mains protection. Selection of points of separation is critical to ensure correct islanded operation, for example when matching demand to generation available.

8) Earthing Arrangement It is essential that systems are adequately earthed when operating separated from the main Distribution System. System containing generators operating in parallel with the Distribution System are normally earthed through the Distribution network. It is important that earthing systems are designed to take into account an islanding operation for example lower fault levels and different load flows, potential multiple grounding points. Earthing islanded systems consisting of more than one generator can also be complex and may require switched earths. Protection systems should take into account the earth switching and its complexities.

9) Protection systems A number of parameters will affect the operation of protection systems when a system is islanded from a Distribution System namely; lower fault levels and different (such as reverse load flows or increased or lowered load flows). Protection systems would need to be capable of switching from a paralleled system to an islanded system.

3.8.5.4 Islanding system could make a difference in costs of supply failure during

forced or planned outages. Where appropriate, case studies should be carried out using real systems to discover benefits, and also costs of realizing the benefits.

33..99 LLoosssseess 3.9.1 Generators do have a significant effect on network losses; it can lower or

increase losses depending on its location and the network configuration. In principle, when a generator is connected to a distribution system, there should not be any increase in losses in comparison to the system without the generator. As an example, Figure 3.8 illustrates a variation of losses under different load levels and generating unit outputs. This example case illustrates the possible increase in losses when a DG unit is connected at the end of a long line. Using the principle of limiting loss level (loss limit line) as indicated in Figure 3.8, the generation output, for this example, could be limited to between 2500kW and 3000kW during light and peak load respectively. However for minimum loss operation, the DG output is limited between 700kW and 1400kW.


- 45 –

0

50

100

150

200

250

300

350

400

450

500

0 1000 2000 3000 4000

DG Output (kW)

Feed

er L

osse

s (k

W)

PeakIntermediateLight

Loss limit line

700 14002500

Figure 3.8: An example of loss variation on different load level and unit outputs

3.9.2 Connecting generators at a higher voltage and/or at a different location can

normally reduce losses. Location can be important because losses can only be reduced if the generator can back-off demand. Essentially, losses are reduced by connecting a generator in high demand areas.

3.9.3 When designing a generator connection, the effect on losses needs to be taken

into consideration. In most cases, there will be an opportunity to reduce system losses and maximize the benefits brought about by the generator and can only be analysed through examination of various network operating conditions.

3.9.4 Losses are calculated by carrying out load flow studies on the system.

Procedures for carrying out the studies are described elsewhere in this Guidebook. Where practical, the methodology for carrying out the studies and assumptions should be made transparent to the DG Developer.

3.9.5 The procedure for calculating losses needs to take into consideration the

following: 1) Demand Profiles – Demand varies throughout the day and also throughout

the year. A number of permutations are possible and accuracy of the results will depend on the number scenarios used throughout the year. In general, the wider the range of demand over the day or year, the more scenarios will be required.



- 46 –


2) Generator output profiles – Similarly, generator outputs profiles can vary. Most DGs will run at constant outputs, depending on the availability of fuel. However, as discussed in chapter 4, there may be occasions that the DG unit is operated to follow a load profile. Any potential long term constraints on generators due to network restrictions should also be taken into account

3) Network Configuration – Generally, changes in network configurations would be less than demand variations. However, any planned network improvements or long term network outages would need to be taken into considerations, especially when it involves transformers. Losses due to transformers would normally be more significant than losses through lines.

4) Voltage profiles - Voltage changes will also significantly affect network losses. Care should be taken when carrying out studies that credible voltage profiles are maintained when varying system demands and generator outputs. This will assist in maintaining consistency across the results.

3.9.6 Methodologies for calculating losses will depend on how the cost of losses is to

be applied. Losses can be capitalized over the project life or ‘loss adjustment factors’ could be applied to generator outputs. Whichever methodology used would need regular reviews to take into account changes within the system.

33..1100 EEaarrtthhiinngg aanndd uussee ooff iinntteerrffaaccee ttrraannssffoorrmmeerrss 3.10.1 Earthing arrangements are discussed in Chapter 4. To ensure robustness of

system earths, it is recommended that generation systems are interconnected to the distribution network using interface transformers as detailed in Chapter 4. There are a number of advantages of using interface transformers, namely; 1) Ensuring that the earthing systems of the generating unit and the distribution

system are adequately and independently earthed. 2) In certain cases, the generator will experience less voltage dips originating

from the Distribution Network. This could reduce the number of generator trippings due to under/over voltage protection.

3) As described elsewhere in this Chapter, it could be a means of reducing the fault level infeed into the Distribution Network.


- 47 –


33..1111 SSttaabbiilliittyy 3.11.1 Generator transient instability is not normally an issue with generators connected

to a distribution system. However, generators connected to very long lines subject to long protection clearance times could experience transient instability. Multiple generator installations could be particularly prone to instability. Stability studies would be carried out to determine the need for additional system and generator protection such as pole slipping protection.

3.11.2 Pole slipping protection system is used to protect the generator from instability

and the damage it could cause. However, this is a non-standard protection and will be an additional cost to the DG Developer.

3.11.3 Studies would also need to identify the pole slipping protection settings

required. The settings would need to take into account instability within the generator and also within the distribution network caused by other generators in the system.

3.11.4 At the onset of a project, it is unlikely that precise data required for stability

studies will be available. It is essential that sensitivity assessments are carried out on estimated generator data in order to identify potential stability problems. Detailed studies may be required once actual data are available, usually when machines are being ordered.

33..1122 OOvveerr vvoollttaaggeess aanndd rreessoonnaanntt oovveerr--vvoollttaaggee 3.12.1 Distribution systems can be prone to over-voltages and resonant over-voltages.

Over-voltages are common and normally caused by: 1) Lightning Strikes – Lightning strikes are common in systems having a high

proportion of overhead lines. Mitigations include installing suitable surge arresters.

2) Switching Surges – These are caused by switching long cables due to their capacitive effects. Similar to the above, installing surge arresters would offer protection.

3) Ineffective Grounding of DG – Voltages can rise in the Generator neutrals and also phase terminal could experience up to twice the phase voltages if generators or systems are incorrectly earthed. The primary protection against this phenomenon would be through the earthing system. Earthing design does need take into account the over-voltage capabilities of the system including generators, especially system insulation levels. NVD (Neutral Voltage Displacement) can be used for protection against these ‘unbalanced’ voltage conditions.

4) Line to Ground Faults – Similar to the above, certain line-to-ground faults in combination with ineffective earthing as described above could give rise to unbalanced voltage conditions.

5) Load rejections – Disproportionate load rejection can cause generators to transiently over-excite and cause over-voltages at the generator terminals. It


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is essential that generator excitation systems are designed and tested to ensure correct response of the voltage control during transient conditions.

3.12.2 Resonant over-voltages are caused by resonant conditions brought about by the

presence of capacitance and inductance in the system. These conditions can be difficult to detect or calculate because the event may only be triggered by certain network configuration for example during an outage condition. Once detected, the system can be ‘detuned’.

33..1133 DDaattaa RReeqquuiirreemmeennttss

3.13.1 As identified in the various sections of this chapter, availability and accuracy of data is a major concern when carrying out studies to determine costs of connections. The reliability of generator data increases throughout the project. At the onset of the project, only estimated data would be available. It should also be noted that manufacturer’s schedules have a tolerance of at least +/-10% on the impedance data as allowed by the IEC standards. Developers would need to ensure that data submitted to TNB are reliable and checked by the Developer’s consultant.

3.13.2 Where data tolerances are given, worst case scenarios should be examined in

the studies. It is also important to understand the sensitivities of the tolerances to the study results. This will identify the level of data accuracy required. The following are some of the issues related to data requirements. 1) Initial Load Flow Studies: Generally, as identified in the Appendices C and

E, data for load flow studies will be very basic. Based on the generator estimated ratings, various impedances can be estimated.

2) Fault Level Studies: TNB’s procedure includes a 10% margin when calculating fault level within the network. This is to allow both network data tolerances and generator data tolerances. When using manufacturer’s data, calculation should be based on the worst case, for example using lower end of the tolerance range of generator impedances.

3) Stability studies: Contrary to the Fault Level Studies, the worst case scenario may need to use the higher end of the tolerance.

4) Protection Studies: In order for the Distribution Network co-ordination studies to be carried out, the Distributor will require protection settings from the DG Developer. The DG Developer will need to ensure that the protection co-ordination studies within the Developer’s site have been completed before submitting data. The timing of the data submission will be detailed in the PPA.

33..1144 SSaaffeettyy 3.14.1 Safety must be a priority when designing Distribution Systems and Generation

systems. Some of the issues that concern safety are discussed in the various sections of this Chapter. Two issues in particular need particular attention.


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1) Earthing Arrangements – The design of earthing arrangements also need to take into account safe touch voltages and safe transfer voltages. Particular attention should be taken systems remote to the main Distribution system and areas of high soil resistivities.

2) Protection systems – Protection system issues have been described elsewhere in this Chapter. Similarly, particular attention should be taken when designing remote generator connections due to the vulnerability of connecting lines and access to equipment.

3.15.2 References should include the following when designing systems:; BS

7671:2001 Requirements for electrical installations. IEE Wiring Regulations. Sixteenth edition. The relevant clauses mentioned include: “Clause 413-02-04: The characteristics of each protective device for

automatic disconnection, the earthing arrangement for the installation and the relevant impedance of the circuit concerned shall be co-coordinated so that during an earth fault the voltages between simultaneous accessible exposed and extraneous-conductive-parts occurring anywhere in the installation shall be of such magnitude and duration as not to cause danger.”

“Conventional means of compliance with this regulation are given in regulations 413-02-06 to 413-02-26 according to the type of system earthing, but equally effective means shall not be excluded.”

The relevant Malaysian Standard to conform to is the MS IEC 60364. The UK’s ESQRC (The Electricity Safety, Quality and Continuity Regulations 2002) and EA Engineering Recommendations give further guidance of step, transfer and voltage gradients for industrial, distribution network and power stations.


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CChhaapptteerr 44:: PPllaannnniinngg,, CCoonnnneeccttiioonn aanndd OOppeerraattiioonn ooff tthhee DDGGss

44..11 IInnttrroodduuccttiioonn 4.1.1 Development of a DG Plant undergoes several phases as described in chapter 2.

The three main phases are planning, connection and operation. Planning are carried out for two main purposes: 1) For the establishment of the DG Plant itself; and 2) For the establishment of the connection to the distribution network. Planning for establishing the DG Plant is carried out by the DG Developer while that associated with the connection is by the Distributor.

4.1.2 When all facilities for connection to the distribution network have been constructed, inspections and tests have to be carried out prior to the commissioning of the connection. Before protection and control equipment are tested, protection setting and coordination studies have to be performed using the data of the installed protective equipment. The results of the coordination studies would be referred to by relay test engineers for setting the protection devices. Another important activity prior to commercial operation is the establishment ‘Connection Operation Manual (COM)’ that must be developed and agreed upon by the DG Developer and the Distributor.

4.1.3 The objective of this chapter is to outline the activities involved in the planning,

connection and operation of the DG Plant. Planning of the connection is performed almost entirely by the Distributor and therefore, it is vital that the DG Developer understands the tasks and types of analysis carried out during the main phases of planning studies namely; preliminary and power system. With respect to connection, the focus is to describe the requirements for protection study and commissioning tests. The chapter will also cover several aspects of DG plant operation particularly on modes of operation and requirements for exchange of operational data and liaisons.

44..22 PPrreelliimmiinnaarryy PPllaannnniinngg SSttuuddyy

4.2.1 Objective 4.2.1.1 On a written request by the DG Developer for cost estimates of connection,

TNB Area/State planning engineers are required to carry out ‘a Preliminary System Study’ so that major equipment and facilities for connecting the DG Plant to the distribution network could be identified and its costs estimated. Such request may also come from within TNB such as the Small Energy Unit (Unit Tenaga Kecil) of TNB Distribution Division for renewable energy projects.


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4.2.1.2 The main objectives of the preliminary system study are: 1) To determine network capability to accommodate the proposed DG; and 2) To establish cost estimate of the connection of the DG Plant to the

distribution network of the part of the circuit facilities that will come under the operational responsibility of the Distributor.

4.2.2 Connection Facilities Under the Distributor’s Responsibility 4.2.2.1 At this preliminary stage, connection facilities that will become the operational

responsibility of the Distributor must be indicated. These facilities could vary depending on the configuration of the connection as shown in Figures 4.1(a), 4.1(b), 4.1(c) and 4.1(d). The configurations must be designed based on the principle of ‘clear system boundaries and responsibilities’.

G

DG Plant

Dual-breaker scheme

G

DG Plant

Three-breaker scheme

Houseload

Utility Utility

FeederFeeder FeederFeeder

Figure 4.1 (a): Connection configuration

GDG Plant

Three-breaker schemeWith bus-coupler & two feeders

G

DG Plant

Three-breaker schemeWith bus-coupler

UtilityUtility


Feeder Figure 4.1 (b): Connection configuration



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G

DG Plant

Remote connection point withDual-breaker scheme

FeederFeeder

Utility

Figure 4.1 (c): Connection configuration

G

G

M M M

M M M

Utility

FeederFeeder

DG Plant &Network

InterfacingFacilities

Figure 4.1 (d): Connection configuration



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4.2.2.2 Figures 4.1(a) and 4.1(b) illustrate connection configurations when the points of interface are located in same premises as the DG Plant. Figure 4.1(c) illustrates the dual-breaker scheme with the interface point remotely located near the utility existing network and this is a typical case of connecting a mini-hydro DG Plant with a long connecting line to the distribution network. In the case of connection configuration in Figure 4.1(c), the DG Operator is also responsible to manage and operate the interconnection line up to the interface point.

4.2.2.3 From distribution network design and operation point of view, the basic

requirements for major DG Plant and interface/connection facilities must include the following facilities: 1) Interface-transformer; 2) Interface-transformer star-grounded through NER; 3) Synchronisation facilities as part of the plant; and 4) Circuit breaker(s). The above facilities could be arranged in several ways as shown in Figure 4.2.

4.2.2.4 The Preliminary System Study report must also indicate the connection and interface facilities that should be provided by the DG Developer including their basic requirements. This information must then be provided by the Distributor to the DG Developer.


NEROne LV Breaker

NEROne HV Breaker

NERLV and HV Breakers

Synchronising

Figure 4.2(a): Basic requirements at the plant for connection to the Distribution network – generator transformers.


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NER

DG Plant &Network

Synchronising

M

M

M

Figure 4.2(b): Basic requirements at the plant for connection to the Distribution network – interface transformer.

44..22..33 BBaassiicc CCoonnnneeccttiioonn IIssssuueess 4.2.3.1 Connection technical issues (see chapter 3) of importance during the

preliminary study are listed below in accordance with the type of DG plant: 1) Hydro: The location of hydro DG in the network is normally remote and

connected through long lines or cables. The main issues are: Voltage and its controls; and Losses

2) Biomass: Biomass plant can be located near existing feeders in rural areas as well as near industrial areas. The main issues are therefore: Voltage and its controls; Losses; and Fault Level

3) Co-generation plant: Co-generation plant is usually located near Grid substations and main issue is: Fault level.


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44..22..44 PPrreelliimmiinnaarryy SSyysstteemm SSttuuddyy PPrroocceedduurree 4.2.4.1 The ‘Preliminary System Study’ starts by developing load flow and short-circuit

model for typical generating units of the DG Plant based on the following basic information provided by the DG Developer: 1) Number of generating units proposed and their capacities; 2) Quantum of power to be sent to the distribution network; 3) Fuel resource; and 4) Physical location of the plant including location map. Based on the fuel resource, the distribution planning engineer could use any of the following typical models available in the simulation software employed by TNB – Shaw PTI’s PSS/ADEPT: a) Steam turbine (small) – biomass units, cogeneration steam units b) Hydro without damper – mini hydro units c) Combustion turbine – gas turbine units

4.2.4.2 The load flow model of the distribution network to which the DG Plant will be

connected to must also be updated with the latest available information including: 1) Feeder and PMU/PPU loadings – peak, intermediate and light or minimum; 2) Fault levels at PMU/PPU transmission voltage level. The distribution planning engineer should then identify options for connection that will be evaluated.

4.2.4.3 For each of the connection options identified, the following

analysis/assessments should be carried out after the simulation models are carefully checked: Network voltage profile under different loading condition and network

contingencies: o Peak, intermediate and light loads o Normal and contingency situations

Any option that violates voltage criteria must be eliminated System Adequacy:

For system adequacy assessment, any branch overload due to introduction of the DG Plant is to be identified for upgrading or reinforcement.

System Losses: Increase or decrease in system losses must be noted and estimated into the future for purposes of related commercial calculations

Short-Circuit Studies: Evaluate fault level – values of above 90% equipment short-circuit rating must be noted

During the study, continuous interactions between the area/state planning engineers and the DG Developer are encouraged to confirm data and assumptions.

4.2.3.4 The cost of each option that satisfy all planning criteria are to be estimated by taking into consideration the following: 1) Investment costs:

Cost of new asset from DG Plant to the existing network; and


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Cost of new internal network reinforcement assets. 2) Operating cost not including losses:

Cost of operating the new asset from DG Plant to the existing network; and

Cost of operating the new internal network reinforcement assets. 4.2.3.5 Losses (increase or decrease) due to the connection of the DG Plant must be

calculated and included in the ‘Preliminary Study Report’. Information on system losses will be used by the Commercial Department of TNB Distribution for tariff calculations. However, the principle to be used with respect to system losses is that ‘the connection of the DG Plant should not result in system losses to be more than when the system is without the DG Plant’.

44..22..55 BBaassiicc PPrrootteeccttiioonn,, CCoonnttrrooll,, MMeetteerriinngg aanndd MMoonniittoorriinngg RReeqquuiirreemmeennttss 4.2.5.1 Amongst others, the preliminary study report should indicate the following

basic requirements for connection: 1) Automatic Disconnection

On loss of mains 2) Synchronization Point and Procedure

On DG terminal Re-synchronizing only proceed once the system is restored to it’s normal

state and sanction given by TNB. 3) Protection at Network Interface

The proposed protection scheme and setting from the DG plant to TNB substations shall be reviewed and approved by TNB.

The purpose of the protection scheme is to ensure proper coordination and integrity of the overall protection system at the interface points.

4) Monitoring of DG Network Operations TNB needs to monitor the status, voltage and flows at interface Monitoring using RTU to be provided DG developer.

5) Metering Point and Systems The metering scheme to be reviewed by TNB. Under Metering Code

4.2.6 Preliminary System Study Report 4.2.6.1 ‘Preliminary System Study Report’ is not normally provided to the DG

Developer. However, TNB is obliged to make presentation of the report to the DG Developer. From experience, the duration required to conduct the ‘preliminary system study’ is about 2 months.

4.2.6.2 TNB is only obliged to provide summary of the results and connection

requirements of the Preliminary System Study Report and connection cost estimates. The DG Developer may then use the results of the Preliminary Study Report to decide whether or not to proceed with the DG project.


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44..33 PPoowweerr SSyysstteemm SSttuuddyy

4.3.1 Objectives:

4.3.1.1 Following confirmation by the DG Developer to proceed, the DG plant project

then enters the design phase. It is assumed that at this point in time the DG Developer would have more detailed information on the DG plant and submits a formal application for connection to TNB (see Appendix C). While basic connection requirements have been identified in the ‘Preliminary System Study’, the objective of the ‘Power System Study’ are: 1) To identify additional controls and protection and operating strategies for the

DG plant when connected to the distribution network. 2) To be used by DG Developer to establish relevant specifications for DG plant

and its interface with the distribution network. 4.3.1.2 Power System Study is currently performed by TNB Distribution Division,

Engineering Services and Logistics Department based in Petaling Jaya. This study is only carried out when all data as required in connection application form have been provided and the study fee is paid to TNB by the DG Developer.

4.3.2 Data Requirements 4.3.2.1 It is important that when the DG Developer submits the application for

connection, data for the following major equipment of the DG unit(s) are provided based on estimates or typical values to be provided as far as possible by the intended manufacturers. The major manufacturer’s data are for: a) Generator electrical b) Generator transformer and grounding c) Generator mechanical d) Generator excitation control e) Generator turbine-control f) Generator other supplementary controls

4.3.2.2 As a follow up to the requirements of the ‘Preliminary System Study’, the DG

Developer must also submit the followings preliminary designs with the application for connections: 1) Protection and control schemes; 2) Synchronisation scheme; 3) Control of equipment and their operation; and 4) Layout scheme of the plant and circuits.


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4.3.3 Power System Study Methods and Analyses 4.3.3.1 Since the data provided by the DG Developer can be assumed to be more

representative of the DG Plant to be established, it is therefore important for the ‘Power System Study’ to revisit the analysis carried out during the ‘Preliminary System Study’, The analysis include: 1) Network voltage profile; 2) System/network Adequacy; 3) System Losses; and 4) Short-Circuit Studies. However, at this stage more detailed analysis is required to identify possible control measures including equipment that would be installed in the DG Plant and interface specifications.

4.3.3.2 When evaluating voltage profile and controls the following inputs on the DG

units must be included: 1) Reactive capability curve; 2) Voltage control capability; 3) Power factor control capability; Voltage profile under at least three load conditions of peak, intermediate and light must be studied for the purpose of identifying the most suitable control method – either voltage or power factor. The evaluation must also take into consideration response of major voltage control equipment in the network such as the main intake transformer in-service tap-changers.

4.3.3.3 Aspects of system/network adequacy should have been evaluated during the

‘Preliminary System Study’ to identify interface and reinforcement requirements and no particular control is associated with this aspect. However, any compensation equipment proposed by the DG Developer (based on the results of the ‘Preliminary System Study’) could impact on the capacity of the network and the interface and therefore this aspect should also be evaluated and reported.

4.3.3.4 Impact on system losses with the connection of the DG is an important aspect

that must be thoroughly examined and cost estimated. This aspect must be evaluated during the ‘Preliminary System Study’. However, there is a need to re-evaluate the losses since compensation and parameters of equipment (including transformer losses) would normally be different from what have been assumed during the ‘Preliminary System Study’.

4.3.3.5 One most important purpose of the ‘Power System Study’ is to identify

measures or controls to limit impacts of increased fault level with the connection of the generating unit. At this stage, it is vital that generator impedance and time constant parameters provided by the DG Developer would represent the values of the DG units to be installed. Any increase in fault of more than 90% of existing equipment rating must be re-evaluated with fault level containment measures – methods are discussed in chapter 3. It is also important to note that apart from fault levels, the analysis must include evaluation of making and breaking


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capabilities of switching equipment in the network particularly those closed to the DG Plant installation.

4.3.4 Additional Analysis in Power System Study 4.3.4.1 Apart from the steady-state analysis described previously and where

appropriate, the Power System Study are to include two major additional analysis, namely: 1) Stability; and 2) Insulation coordination.

4.3.4.2 It must be emphasized that the main purpose of the stability analysis is to

examine and analyse electromechanical transient responses of the DG unit under various system faults and contingency situations so that necessary measures could be specified to avoid potential damaging effects on the DG units. For purposes of dynamic analysis, all generating units in the distribution network must be modelled in detail. The transmission main intake source(s) could be modelled as an infinite bus, that is, a classical generator with inertia constant (H) of zero.

4.3.4.3 The DG Developer when submitting the application for connection must pay

particular attention to the data required for dynamic modelling of the generating units. It is essential that the DG Developer obtains the services of experienced consultant who would be able to provide accurate information for the dynamic modelling of the DG Plant. Responsibility of estimating dynamic models of the DG Plant should not be relegated to the Distributor who is carrying out the Power System Study.

4.3.4.4 In carrying out stability analysis of the DG Plant connected to the distribution

network, the following factors that can affect generator stability must be noted and taken into consideration when necessary: a) Generator loading – the more the generator is loaded, the more advanced is

the rotor angle; b) Generator output during the fault which depends on the fault location, type,

and severity; c) Fault clearing time - in distribution system, long clearing time of protective

device following fault could result in loss of synchronism; d) Post fault system reactance - loss of lines/ cables would change reactance; e) Generator reactance - a lower reactance increases peak power and reduces

initial rotor angle; f) Generator inertia - the higher the inertia, the slower the rate of change of

rotor angle and reduces the kinetic energy gained during fault; g) Generator internal voltage magnitude - this depends on the field excitation;

and h) Transmission source voltage magnitudes.


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4.3.4.5 As a minimum, response of the generating unit(s) to the following contingencies must be evaluated and analysed: 1) Determine critical fault clearing time for 3-phase-to-ground fault on the star

side of the generator transformer (see Figure 4.3); 2) 3-phase fault for 500 ms at the main intake transformer secondary side

followed by loss of the feeder to the DG Plant (see Figure 4.4). 3) 3-phase fault for 500 ms on a bus in the feeder followed by loss of a spur

line/section supply large load. Other contingencies to be applied must be considered depending on the network configurations, including: Presence of other generating units in the distribution network; Presence of large motors where its starting behaviour need to be examined;

4.3.4.6 Where appropriate the following contingencies should also be analysed:

1) Determine critical fault clearing time for 1-phase-to-ground fault on the star side of the generator transformer (see Figure 4.3);

2) 1-phase-to-ground fault for 3 seconds at the main intake transformer secondary side followed by loss of one main intake transformer;

NER Fault

Figure 4.3: Fault for determining critical fault clearing time



- 61 –

DG

S

Reactor

Main Intake

DG Plant

Feeder 1

Feeder 2

Feeder 3

Feeder 3

Feeder 3

1. Fault

2. BreakerOpened

Figure 4.4: Fault at main intake transformer secondary and loss of feeder to DG Plant

4.3.4.7 In addition to transient stability analysis, the Power System Study, where appropriate, may also include an ‘insulation coordination’ analysis to examine the following two aspects of the DG connection: 1) Lightning over-voltages and arrester requirements at the interface point for

overhead line feeder; 2) Switching over-voltages under fault and load rejection conditions as well as

possible self-excitation (may also be examined using transient stability analysis)

The transient over-voltages must be compared with the standard BIL and LIL of the distribution equipment normally employed by TNB.

4.3.4.8 Control measures that could be applied to mitigate stability problems include:

1) Power system stabiliser (PSS); 2) Generator tripping scheme; 3) Generator intertripping scheme; 4) Dynamic brake; and 5) Pole slip protection.



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4.3.5 Power System Study Report and Liaison 4.3.5.1 Power System Study report must be submitted to the DG Developer upon

completion and the study must be completed within 4 months from the receipt of application for connection with the complete data.

4.3.5.2 During the duration of the study, continuous interactions and communications

between DG Developer and Distributor are encouraged to clarify data and assumptions used for the studies.

44..44 CCoonnnneeccttiioonn ooff tthhee DDGG PPllaanntt ttoo tthhee DDiissttrriibbuuttiioonn NNeettwwoorrkk

4.4.1 Connection Point and Connection Process 4.4.1.1 The connection point is a site in the distribution network at which the DG Plant

network connects the Distributor’s MV distribution network. Identification of the connection point is not meant to imply ownership of apparatus adjacent to the connection point. For practical purposes, a connection point is designated as the MV circuit breaker that is under the operational responsibility of the Distributor located at the interface. These connection points are also indicated in Figures 4.1(a) through 4.1(c).

4.4.1.2 Connection process comprises of activities to be carried out when all

interfacing equipment are installed and before electrically connecting the DG Plant to the distribution network. These activities are: 1) Protection coordination study; 2) Protective equipment tests and settings; 3) Inspections and pre-commissioning tests; 4) Commissioning procedure; and 5) Plant commissioning and tests. The above activities are described in the following sections. Protection systems drawings must be submitted to the Distributor for approval prior to any Commissioning.

4.4.2 Protection Coordination Study 4.4.2.1 In order for a distribution network having a DG Plant to operate safely and

reliably, the protection devices in both the DG Plant and the distribution networks must be properly coordinated. Coordinated operation of the protection devices ensures that no damage to equipment could result due to flow of fault currents and that only selected components of the network would be isolated to remove the fault.

4.4.2.2 With the connection of a generator to the distribution network, the fault current

contribution would normally increase and if the generator is connected near to the main intake substation, the fault level could exceed the short-time rating of nearby equipment in the network. With the changes in the value of the fault current and to ensure proper operation of protective devices, resetting and


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coordinating of the affected protective devices are required and this is performed through ‘Protection Coordination Study’.

4.4.2.3 Protection coordination study is carried out in two Phases:

1) Phase 1: DG Plant relay setting and data exchange 2) Phase 2: Distributor relay coordination study

4.4.2.4 In Phase 1, the following procedures are to be carried out by the DG

Developer: a. Request TNB for short-circuit levels – 3-phase fault and 1-phase-to-ground

fault – at the point of interface with TNB; b. Calculate settings of all relays in the DG Plant. In this case, the DG Developer

should propose settings for the protection of the DG Plant equipment disregarding any coordination with the utility distribution protection;

c. DG Developer to submit a ‘DG Plant Protection Setting Report’ to TNB addressing the following aspects:

• Protection philosophies adopted; • Short-circuit limits including making and breaking capacities of

equipment - breakers, cables, lines etc. • Generator limits - reactive, active power, field current and voltage

limits, over-speed and under-speed; • Documents or references on characteristics of the relays and fuses

employed; • Breaker operating time – time taken from receipt of tripping signal

from relays to full opening of breaker contacts; • Proposed settings/coordination curves (if applicable) of relays in the

DG Plant and the reasons for the chosen setting; and • Other important limits on the DG Plant equipment that the Distributor

should know. 4.4.2.5 Upon receipt of the ‘DG Plant Protection Coordination and Setting Report’, the

Distributor must examine the report particularly the protection philosophies and data on protection relays. In Phase 2, the Distributor must carry out a ‘Protection Coordination Study’ with the assumption that the DG Plant is connected to the distribution network. The ‘Protection Coordination Study’ Report should address the following aspects: The proposed relay settings and their coordination; and Changes required, if any, on the DG plant relay settings and the reason for

the changes.


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44..44..33 PPrrootteeccttiivvee EEqquuiippmmeenntt TTeessttss aanndd SSeettttiinnggss 4.4.3.1 Protective equipment including relays must be tested in accordance with

prudent utility practices to confirm that they are in good working condition after installation. When all tests are satisfactory, the relays could then be finally set to the approved setting values.

4.4.3.2 Secondary injection tests are usually carried out to ensure that protective

relays, meters and other control equipment are installed and wired properly and in good condition for service. For each protective relay, its approved operating settings (see 4.4.2 on protection coordination study) will be set following completion of the tests. It is the responsibility of DG Developer to carry out the tests for protective and control equipment within the DG Plant.

4.4.3.3 Tests and setting of protective relays at the interface/connection points and its

associated equipment (current and voltage transformers) should normally be carried out by the DG Developer using services of licensed test engineers approved by the Distributor. The tests and settings programme must be coordinated with the Distributor to ensure that all safety switching requirements are met and that the Distributor representatives are available for witnessing the tests.

4.4.3.4 Prior to carrying out protective equipment tests and settings at the

interface/connection points, the DG Developer should submit the following to TNB: 1) Test programme; 2) List of equipment to be tested; 3) Test methods/procedures; 4) Access requirements to TNB’s sites or part of the network. Tests of protective equipment at the interface should only be carried out with the approval of TNB of the test programme.

4.4.3.5 In addition to testing of protective equipment, check and tests must be carried

out on DC equipment and control circuits. Test of the DC equipment is of main interest of the utility since in many cases, this facility is shared with the DG Plant.

4.4.3.6 On completion of protection and control tests, the DG Developer must submit

the test reports to the Distributor for approval prior to commissioning and energising of the connection.


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44..44..44 IInnssppeeccttiioonn aanndd PPrree--CCoommmmiissssiioonniinngg TTeessttss 4.4.4.1 Prior to commissioning of the connection and thus parallel operation of the DG

Plant to the distribution network, inspections and pre-commissioning tests should be carried out. It is the responsibility of the DG Developer to perform inspection and pre-commissioning tests for the DG Plant and its network. However, for the interface/connection equipment, it is the responsibility of the Distributor. The inspection and pre-commissioning tests should be initiated by the DG Developer and coordinated with the Distributor. At this point in the connection process, all protective devices are set and test reports are submitted and approved by the Distributor.

4.4.4.2 Inspections that need to be carried prior to commissioning and energisation

are visual examinations of the following conditions or equipment: a) General inspection of connection equipment & facilities; b) Site conditions – should be free from leftover construction debris particularly

that may pose safety hazards; c) Grounding – all electrical equipment must be adequately grounded; d) Nameplate information – ensure that approved nameplate information are

sufficiently clear and installed in accessible locations; e) Labelling – equipment and safety labels must be clearly visible and

noticeable; f) Clearances – ensure that clearances to live parts are within safety

requirements; g) DC system – final tests should be carried out on tripping of circuit breakers

and functioning of control circuits supplied from the DC supply; h) Control wiring – visible inspection of control wiring to ensure that they

properly segregated and bunched; i) Switches – tests of all switches to ensure that they are working properly

including full closing and opening and operation of motorized mechanism, if any;

j) Breakers – ensure that circuit breaker auxiliary tools are in place and the truck racking in and out operations are tested;

k) Surge arresters – visual inspection to ensure that arresters are installed and connected to the lines and it's grounding is properly connected with no sign of damage to the arrester housing; and

l) Transformers – inspection of the physical conditions of transformers including signs of oil leaks, colour of silica gel, connections and grounding.

It is a normal practice for the DG Developer to prepare a check list of particulars to be inspected and verified for each of the above items.

4.4.4.3 Pre-commissioning tests that are normally carried out include:

a) Earthing resistance measurements; b) Discharge and recharge tests of DC batteries; c) Test circuit breakers for electric trip and close, manual trip and close, breaker

operation time, insulation level, interlocks and status indicators, heaters; and d) Transformer test include; oil dielectric tests, winding configuration and phase

check, turns ratio, insulation tests of windings etc.


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44..44..55 CCoommmmiissssiioonniinngg PPrroocceedduurree 4.4.5.1 Prior to commissioning of the DG Plant and the interface/connection, the DG

Developer in consultation with the Distributor should identify step-by-step energisation of equipment before synchronization. If there is doubt as to the impacts on system performance during the energisation, simulation of the energisation sequence may need to be performed to ensure network conditions will remain within criteria limits. This is particularly important when energizing DG Plant involving long lines with reactive compensation. Energisation procedure document should include: List of precautions to be taken during energisation; Ensure that other tests (see section 4.4.3 and 4.4.4) are completed and

approved; Identify steps for connecting

4.4.5.2 As an example, steps for connecting the DG Plant in Figure 4.5 to the

distribution network could comprise of the following steps: 1) Ensure that breaker BR3 is opened and line BR4 – BR3 ready to be energized

and all safety earthing removed; 2) Close switch BR4; 3) Live test incoming voltage at BR3; 4) Rack-in breaker BR3; 5) Close SW4 of shunt reactor; 6) Close breaker BR3; 7) Record voltage at DG Plant busbar; 8) Energise auxiliary transformer through SF2; 9) Open generator turbine control valve and run generator to full speed; 10) Excitation controller on manual until terminal voltage magnitude is reached; 11) Set AVR on automatic control; 12) Set governor on speed control; 13) Close breaker BR1 and this energises the generator transformer; 14) Ensure the synchronisation parameters are within limits and synchronise

through closing of breaker BR2.


- 67 –

G

From source SW1 BR4 SW2

SF1

BR3BR2

SF2

BR1

SW4AVR

Governor

Figure 4.4: Example system for energisation procedure


44..44..66 PPllaanntt CCoommmmiissssiioonniinngg aanndd TTeessttss 4.4.6.1 As described in an example in 4.4.5.1, typical energisation steps are:

1) Energize circuits from utility side 2) Auxiliary transformer 3) Generator 4) Generator transformer 5) Synchronisation

4.4.6.2 In the case of the synchronization point being located on the generator

breaker, it is usual to energise generator-transformer from the utility side. Otherwise as in Figure 4.5, the generator transformer is energized from the generator and this is to be done after the generator has reached full speed and attained full terminal voltage.

4.4.6.3 When energizing the synchronous generator, the generator will initially be in

open position. The turbine is first operated manually to full speed. Excitation should only be applied when the speed is more than 90% of rated speed. Both turbine and excitation controls are manually adjusted until full speed and the terminal voltage is reached.


- 68 –


4.4.6.4 Before synchronization is performed, ensure the followings are verified: Generator phase voltages are well balanced – line-neutral voltage difference

should not exceed 1%; Line-to-line and line-neutral voltage are related by factor of /3; and Phase rotation of generator voltage to be compared with utility side voltage.

Synchronisation is carried using synchroscope where all parameters are satisfied before the synchronising breaker is closed.

4.4.6.5 Following successful synchronisation and parallel operation of the DG Plant

with the distribution network, the following tests and checks are normally carried out: a) Load rejection tests;

To verify dynamic response of generators b) Loss of mains test or anti-islanding test; and c) Final site checks.

4.4.6.6 Before load rejection tests are carried out, recording equipment that will not

only measure electrical quantities (AC and DC) but also mechanical quantities such as speed and valve positions should be installed. Real and reactive power load rejection tests are carried out to record and verify dynamic response of the unit. Opportunity must be taken to perform load rejection tests whose results could be used to verify and derive generator parameters including excitation and governor controllers. The tests comprise of staged test at several active and reactive power output with excitation controllers in manual and automatic modes. The procedure for load rejection tests would be discussed with Distributor and normally the Distributor would absorb the generator output power during the tests.

4.4.6.7 Loss of mains tests should be carried out to ensure that the generating plant is

isolated from the distribution network when any of the utility-side circuit breaker is opened. An agreed test procedure should be developed between the DG Developer and the Distributor. The DG Plant Operator should note that loss of mains protection may not operate at times and should take reasonable precautions. It may be appropriate that ROCOF type relays be monitored and studied for its performance.

4.4.6.8 Final site checks should then be carried out before leaving the plant operating

in parallel with the distribution network. These checks are visual inspection of all major equipment in the plant including, light indicators, transformer noise level, corona noise, oil leaks, temperature etc.

44..44..77 EEssttaabblliisshhmmeenntt ooff ‘‘CCoonnnneeccttiioonn OOppeerraattiioonn MMaannuuaall’’ 4.4.7.1 ‘Connection Operation Manual’ is a document to be jointly prepared by the DG

Developer and Distributor outlining procedure to be followed for operation of the connection of the DG Plant to the distribution network. This document is technical and procedural in nature. One important element that must be included in all operating procedures is the safety aspect.


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4.4.7.2 Typical contents of the COM include but not limited to the followings: 1) Objectives of the COM – could be slightly different from the perspective of

each party; 2) Description of the connection/interface facilities and responsibility of each

party: Circuit breakers, isolators Synchronizing equipment Interlocking system Grounding/earthing facilities Protection and controls Metering

3) Liaison and Communication – communication methods and procedures, and contact persons;

4) Switching and isolation procedure – a step-by-step switching procedure for all major equipment at the interface/connection point as well as the DG Plant;

5) Procedure for Reporting/Notifications of Events/Outages/Faults; 6) General outline of DG Plant maintenance requirements; 7) Emergency Operation Procedures


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44..55 OOppeerraattiioonn ooff tthhee DDGG PPllaanntt wwiitthh tthhee DDiissttrriibbuuttiioonn NNeettwwoorrkk

4.5.1 Control Operation 4.5.1.1 Normally the day to day operation of the DG Plant is the responsibility of

the DG Operator. However, the Distributor may need to exercise control under the following circumstances: When the DG plant is operating on varying output mode; For safety reasons; For reasons associated with supply reliability; and For reasons associated with power quality.

4.5.1.2 Control needs for reasons as listed above or any additional reasonable

basis must be included in the ‘Connection Operation Manual’.

4.5.2 DG Operating Modes 4.5.2.1 In terms of power output into the distribution network, a DG Plant could be

operating in any of the following modes: 1) Constant MW output for the whole day 2) MW output following load demand – load following 3) MW output depending fuel supply variations 4) Zero MW output

The first two operating modes are illustrated in Figure 4.5.

DistributionMW profile

ConstantMW

Load following

MW

Time 24-hours

Figure 4.5: DG Operating Modes 4.5.2.2 For a DG Plant with constant MW output, it is a practice to ensure that the DG

output will remain 15% below the minimum load of the distribution network as illustrated in Figure 4.6.


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DG

TransmissionNetworkDistribution

Network

MWLoad Profile

Lmin

Lpk

Hours

15%

DG Output to remain 15% below minimum load or

less

Figure 4.6: Constant MW output to remain 15% below minimum daily load 4.5.2.3 ‘Load following’ operating mode allows the DG plant output to be varied over

the 24-hour period so that its output would remain 15% below the total system demand as illustrated in Figure 4.7.

DG

TransmissionNetworkDistribution

Network

MWLoad Profile

Lmin

Lpk

Hours

DG Output to remain 15% below load or

less

Figure 4.7: Load following mode with MW output to remain 15% below load profile


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4.5.2.4 The MW output of a DG Plant could vary depending on availability of fuel and this is typical of biomass DG Plant. In this case of operating mode, the maximum MW output of the DG plant must remain 15% below load profile.

4.5.2.5 For all operating modes, the Distributor must be notified of the scheduled

output of generator on weekly and daily basis and this procedure is carried out under the operation planning process discussed below.

4.5.3 Distribution Operation Planning 4.5.3.1 Distribution Operation Planning is a task carried out by the Distributor to

establish Operation Plan that contains strategies on how the distribution network should be operated under normal and abnormal conditions following contingencies after taking into consideration several items including scheduled output of DG Plants. The main objective of the Operation Plan is to ensure that security supply is maintained to all customers inline with the requirements of operation criteria. It is usual for the Distributor to establish an ‘Annual Operation Plan’ that is reviewed on monthly basis and be used on daily basis for a day a head operation.

4.5.3.2 Two major inputs to the ‘Annual Operation Plan’ are scheduled weekly profile

of DG Plant outputs in MW and MVAR and scheduled maintenance outages of the DG Plant. Using these two inputs together with other network information, the Distributor would establish plans for network operation. One important results of the Operation Plan that of interest to the DG Operator is the scheduled output of DG Plant particularly those that have to be limited due to network and demand constraints.

4.5.3.3 The ‘Annual Operation Plan’ should also contain liaison and communication

information between Distributor and the DG Operator.

4.5.4 Exchange of Operational Information 4.5.4.1 Distribution network operation is usually organized with control responsibility

being assumed by a control centre and/or a supply management centre. The control centre monitors, controls and operates the distribution network and have direct communication with the Transmission Network Operator as well as DG Operators.

4.5.4.2 To coordinate the operation of the distribution system, the Distributor and all

other connected entities including the DG Operator must maintain communication and exchange information on operations and events. There are four major occasions where operational information are to be provided by the DG Operator to the Distributor: Information for Annual Operation Plan and monthly review; Notification of operations; Notification of events; and Reporting of faults and/or outages.


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Exchange of the above information and other relevant information must be included in the Connection Operation Manual (COM). Typical information for Annual Operation Plan to be provided by the DG Operator to the Distributor are discussed in 4.5.3

4.5.4.3 DG Operators must notify the Distributor of any operation that will have or may

have an effect on the distribution network including but not limited to the following : a) implementation of scheduled outages of plants and / or equipment which has

been reported and arranged previously; b) switching operation that will result in temporary disconnection at the point of

interface to the Distributor’s distribution system; c) switching operation for paralleling of system; d) generating unit synchronizing; and e) changes in voltage controls.

4.5.4.4 The notification to the Distributor must contain sufficient detail describing the

operations, and locations of equipment and must be provided before the implementation of the operations. Likewise, in case of any operation in the distribution system, which to the opinion of the Distributor, will have or may have effects on the DG Plant, the Distributor should inform the DG Operator of such operations.

4.5.4.5 DG Operators must also notify the Distributor of any event in their system

which has had or may have had an effect on the distribution network including but not limited to the following: a) the activation of any alarm or indication of any abnormal operating

conditions; b) breakdown of or faults on, forced or partial outages of plant and/or apparatus

including protection and controls; c) increased risk of inadvertent protection operation; d) operation of plant and / or apparatus either manually or automatically; and e) occurrence of voltage levels outside the required limits;

4.5.4.6 The notification to the Distributor must be given in sufficient detail to describe

the event and locations of equipment immediately by phone after the event has occurred to allow for the Distributor to make the necessary assessment on the implications of the event and if necessary to make adjustment to the distribution system. This is normally followed by a detailed written report submitted to the Distributor. Similarly, in case of any event that has occurred in the distribution system that has had or may have had effects on DG Plant, the Distributor should inform the DG Operator.

4.5.4.7 When forced outages or any significant event has occurred in the DG Plant

which have or may have resulted in interruption of supplies to Customers in the Distributor’s distribution system, the DG Operator must verbally inform the Distributor of the event providing the details of sequence of events known at that time leading to the supply interruption. Both DG Operator and Distributor shall coordinate actions to restore supplies to Customers according to the required security levels.


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4.5.5 Operating and Safety Requirements 4.5.5.1 It is important that for the safety of operating staff and public, both the

Distributor and the DG Operator must coordinate, establish and maintain the necessary isolation and earthing when work and/or tests are to be carried out at the interface/connection point. The safety coordination applies to when work and/or tests that are to be carried out involving the interface between the distribution network and the DG Plant and it is the responsibility of the Distributor and DG Operator to comply with the requirements of statutory acts, regulations, sub – regulations, individual license conditions, Standardized Distributor’s Safety Rules and the Malaysian Grid Code.

4.5.5.2 For purposes of safety coordination procedure, the following requirements are

prerequisites: a) at each point of interface/connection between the distribution network and

the DG Plant, the boundary of ownership is clearly defined; b) the Distributor and the DG Operator provide each other with the operating

diagrams of their respective side of the point of interface/connection; c) the Distributor and the DG Operator must exchange information on safety

rules and / or instruction as practiced in their respective system. The above information must be included in the Connection Operation Manual.

4.5.5.3 All switching operations shall be carried our according to the procedures as

defined in the Standardized Distributor’s Safety Rules (TNB Safety Rules), which shall include but not limited to the following: a) Coordination; b) Isolation; c) Earthing; d) Recording; e) Testing; f) Commissioning; g) Cancellation; and h) Reenergizing.


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CChhaapptteerr 55:: IInntteerrffaaccee DDeessiiggnn RReeqquuiirreemmeennttss aanndd NNeettwwoorrkk RReeiinnffoorrcceemmeennttss

55..11 IInnttrroodduuccttiioonn 5.1.1 An interface between a DG plant and the distribution network comprises of the

following set of equipment: protection and control of the connection; metering facilities for measurements of power and energy; and SCADA facilities for remote monitoring and controls.

A connection interface in relation to the distribution network and operation centre as well as the DG Plant is illustrated in Figure 5.1.

ConnectionInterface

DistributionSystem

TransmissionSystem

DistributionOperation/

ControlCentre

M

CBCB

Sync

DG Plant

Communication/Data exchange

Pt, Qt

Figure 5.1: Connection interface 5.1.2 Many technical issues identified in chapter 3 and its analysis as described in

chapter 4 can be resolved and addressed by having a proper interface design. However, there are technical issues that cannot be addressed at the interface but may have to be incorporated in the DG plant at the design stage.


- 76 –

5.1.3 The main objective of this chapter is to summarise the requirements of typical interface design and equipment. In addition to this, the chapter will also discuss the types of reinforcements in the distribution network that may become necessary with the connection of the DG Plant. This chapter will also indicate how connection costs are calculated including the aspects on losses. The topics covered in the chapter are: 1) Basic Connection Interface Requirements 2) Utility Access 3) Synchronisation 4) Protection and Control 5) Interlocking 6) Metering 7) SCADA and Automation 8) Communications 9) Network Reinforcements 10) Cost estimation


55..22 BBaassiicc CCoonnnneeccttiioonn IInntteerrffaaccee RReeqquuiirreemmeennttss

5.2.1 Isolation 5.2.1.1 The designated connection point of a DG Plant to TNB network must include a

means of isolation the two systems (DG Plant/Network and TNB Distribution Network). The following are requirements for the isolation point: a) It must be suitably labelled; b) It must be capable of safety isolating the whole of the DG output from the

TNB’s Network.; c) It must have facilities to permit work to be undertaken on the TNB network

without danger to staff; d) Isolation must be lockable in the isolated position in accordance to TNB’s

standard safety locking procedures; The above requirements are illustrated in Figures 5.2(a) and 5.2(b). Figure 5.2(a): Basic interface/connection point requirements – 3-breaker scheme

G

DG Plant

Feeder

Isolation point:•Isolate from TNB network•Suitably labeled•Safely isolating DG output

•When opened cannot synchronise (interlocked with synchronising switch)

•To permit work•Grounding requirement

•Lockable

Interlocked


- 77 –

Figure 5.2(b): Basic interface/connection point requirements – two breaker scheme

G

DG Plant

Feeder

Isolation point:•Isolate from TNB network•Suitably labeled•Safely isolating DG output

•When opened cannot synchronise (interlocked with synchronising switch)

•To permit work•Grounding requirement

•Lockable

Interlocked

5.2.2 Connection through Star-Delta Transformer 5.2.2.1 Although the design and configuration of a new DG Plant is the responsibility

of the DG Developer, there are basic requirements to be met for ensuring safe and secure operation of the integrated systems. These basic requirements applicable to the DG Plants are: 1) The Generator star shall be earthed or grounded. 2) The choice of generator neutral grounding is up to the DG Developer.

However, the followings should be noted: normally DG units are designed to withstand maximum 3-phase fault

current but not necessary unrestricted phase-to-ground fault current; and use resistor to limit earth-fault current to 300A irrespective of size is a

common practice with step touch voltage within the criteria limits. 3) Two-or three winding transformer with star winding on the Distributor’s side. 4) The star side of the transformer which connects to the Distributor’s network

shall be grounded through an NER designed to limit earth fault current of 150A to flow from the generator side on a single-line to ground fault on the star side of the generator transformer (see Figure 5.3).

5) An earth fault relay must be installed to detect earth faults on the Distributor’s network fed from the Generator and to disconnect the DG network from TNB’s network.

5.2.2.2 Where a DG Plant that has its own network and comprising of more than one

generating units, an interface transformer as illustrated in Figure 5.4 shall be required. For this case the star-side of the interface shall be grounded as described above. It is recognised that existing installation may not currently be connected through interface transformers. For these existing installations, including generating plant upgrades, may not require interface transformers.



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NEREF Relay

1-phase to ground fault

150A

DistributionNetwork

DG Plant

Figure 5.3: Earthing/grounding at the interface

G

G

M

M

TransmissionSystem

Pt, Qt

DG Plant/Network


Interface throughDelta-star transformer

Figure 5.4: DG Plant/network interface through delta-star transformer

55..33 UUttiilliittyy AAcccceessss 5.3.1 To enable TNB's operational staff a 24-hour access to the switchgear and

equipment that TNB has operational responsibility for, consideration should be given to the location of the interface or connection point to permit such access. Access off an all weather road surface is preferred where this is practicable, otherwise delays will be experienced.


- 79 –

5.3.2 It is acceptable that the interface/connection control panel under TNB’s responsibility be located in the same premises or building as the DG Operator control panels. However, visible and clear indication must be provided to distinguish TNB’s control panels from those under the operational control of the DG Operator. Access procedure to the interface/connection point must be stipulated in the Connection Operation Manual (COM). The COM must address access to the following equipment: Control and relay panels; Circuit breakers; Metering; Interlocking control; Locking devices.


55..44 SSyynncchhrroonniissaattiioonn 5.4.1 DG unit control system must include synchronization facilities to enable the

generator to be connected to the distribution network, Control facilities and methods to be employed for synchronization will need to be approved by TNB. An automatic synchronizing panel from a recognized manufacturer, designed for the type of machine proposed, will normally be acceptable.

5.4.2 Synchronisation point is usually a breaker under the operational responsibility of

the DG Operator. This synchronization point and the breaker must be adjacent to the breaker under the operational responsibility of TNB. Locations of synchronizing facilities for various connection configurations are illustrated in Figures 5.5 and 5.6.

G

DG Plant

Dual-breaker scheme

G

DG Plant

Three-breaker scheme

Houseload

Utility Utility


InterlockSynchronisationpoint

Figure 5.5: Synchronisation points and interlocks (1)


- 80 –

GDG Plant


G

DG Plant


UtilityUtility


Feeder

InterlockSynchronisationpoint

Figure 5.6: Synchronisation points and interlocks (2)

5.4.1 For synchronising synchronous generator to the distribution system the synchroscope should be able to detect that the following limits be satisfied before closing of the breaker is allowed: a) Frequency difference: < 0.2 Hz; b) Voltage magnitude difference: < 10%; c) Voltage angle difference: < 10 degrees; and d) Interlocking logics are satisfied. Frequency/speed is adjusted for the generator by the governor control and the voltage magnitude by the excitation control. The voltage angle is used to indicate that there is no gross mistake in vector groups of the two systems and therefore the limits on voltage angle difference may have to be relaxed depending on the system.


55..55 PPrrootteeccttiioonn aanndd CCoonnttrrooll

55..55..11 PPrrootteeccttiioonn 5.5.1.1 The protective scheme must be based on the need to detect system faults and

malfunctions both within the DG installation as well as the distribution feeder. On detection of fault or malfunction, the relays must trip appropriate circuit breakers to isolate the faulty section: to minimise equipment damage and safety hazards during the faults; and to maintain power supply continuity on healthy parts of the system.

Although the design and types of protection for the DG installation is the responsibility of the DG Developer, the Distributor must ensure that these protections are properly coordinated for reliable and safe operation of the distribution feeder (see section 4.4). See also Appendix F for details on protection practices in TNB


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5.5.1.2 The basic requirements for the types and design of the protection schemes are that: 1) For any internal fault within the DG installation, the DG must not cause

problems to the utility system and the utility customers; and 2) For any distribution network fault outside the DG Plant, the generator must

be protected from any damaging effects. 5.5.1.3 For generating units directly connected to the distribution network, the

following protections are required: a) Under Voltage (UV); b) Over Voltage (OV); c) Under Frequency (UF); d) Reverse Active Power (RP); e) Overcurrent (OC); f) Earth fault (EF); g) Step up transformer protection; (above 5 MVA transformer size

recommended to include transformer unit protection); h) Loss of system synchronisation / Field failure relay (FF); The following paragraphs describe the reasons for the requirements of the above protection. For generating units, embedded within its own network, items a, b and c are required at the connection point. For these generating units, items e, f and g will be required for the connecting cables and the interface transformers. These minimum requirements are detailed in Appendix F, Section F.3.

5.5.1.4 UV and UF relays are designed to trip the generator when the distribution

feeder is taken off (loss-of-mains). When the feeder is supplying load greater than the capacity of the generator, under-frequency and under-voltage are expected to occur to trip the generator. The setting of the under-frequency trip (Hz) must be based on the recommendation of the manufacturer. If the feeder load to be supplied by the generator is less than the generation, over-frequency will occur and therefore OF relay is required. The setting of the OF relay must also be based on the recommendation of the generator manufacturer. However, when the feeder load is sufficient to be supplied from the generator under islanded operation, UV, UF or OF relays may not operate and special relays such as ROCOF and Vector Shift will be required (see section 3.8).

5.5.1.5 If the resulting feeder load could be totally supplied by the generator under

islanded operation, this may present a hazard to personnel. Generator damage would be likely when the feeder breaker is reclosed. In distribution systems, feeder breakers are not equipped with dead line check to prevent reclosing on live feeder. An alternative to dead line check relays is an automatic transfer trip that upon opening of the utility feeder breaker, a signal is provided to trip the generator. Any islanded operation required later must be performed based on operation and safety procedures agreed by both the generator and the utility.

5.5.1.6 OV relays are installed on the DG side to protect against over voltages

resulting from a sudden loss of load. However, the generator voltage regulator will take care of the over voltage by reducing excitation. Therefore, the over-voltage relay would be useful if when the voltage regulator is defective or limited that it would result in sustained over-voltage. Transient over-voltages due to


- 82 –


switching or lightning should be catered for by the design of the distribution network and DG system insulation level and coordination.

5.5.1.7 To prevent damage on the prime mover (turbine system) due to motoring of the

generator during reversal of power, RP or directional relays are installed. Time delay must be incorporated to prevent nuisance tripping during synchronization of the generator.

5.5.1.8 Combined over-current and earth-fault (OCEF) relays are employed for

protection of over-current and earth-fault in both directions. IDMT relays equipped with instantaneous trip are used in this case. For large generators provided with its own unit protection, the OCEF relays are used as backup for the generator internal fault. During distribution system fault, both generator OCEF and feeder OCEF would see these fault currents. Coordination of the generator OCEF relays with that of feeders would become more difficult due flow of fault currents from both sources into fault. It is normal practice that on a distribution fault on the feeder, the feeder OCEF is allowed to trip first followed by the generator. If the fault is cleared and the generator operates in isolation then frequency and voltage relays would likely to operate depending on the generation-demand balance. However, if inter-trip is provided, the generator would also be tripped out.

5.5.1.9 Loss of synchronism manifested into generator over-speed or under-speed

that would be detected by the generator mechanical speed relays. 5.5.1.10 Field failure (FF) relays are employed to detect malfunction of the generator

excitation field. Upon loss of excitation, the generator rotor accelerates to above synchronous speed where it continues to generate power as an induction generator. Loss of field is normally detected by an undercurrent relay connected to a shunt in the field circuit.

5.5.1.11 Negative phase sequence relays are employed to detect excessive unbalanced

loading of the generator.

55..55..22 CCoonnttrroollss 5.5.2.1 To provide for safe and flexible operation of the DG Plant and its

interconnection, the followings controls are required: 1) Breaker controls; 2) Turbine-governor controls; 3) Excitation controls; 4) Synchronising controls; and 5) Emergency trip controls.

5.5.2.2 Basic breaker controls functions are ‘trip’ and ‘close’ both at local and remote

locations. Typical features for breaker controls must include:


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a) For synchronizing breaker, the ‘close’ control must be operated through synchronizing control and close only when conditions listed in 5.3 are satisfied.

b) Interlocking control logic. 5.5.2.3 DG unit connected to MV network must be equipped with automatic turbine-

governor control for several purposes: For load following; For control of generator speed during load rejection and loss of mains.

For small DG unit with constant output power mode, it may not be required to have automatic governor control provided that the generator will not be susceptible to damages following protracted over- or under-speed conditions. However, all units must have means to control turbine output manually for starting and shutting down.

5.5.2.4 DG unit must be capable of both voltage and power factor controls. Both of these controls are discussed in chapter 3. These controls are achieved through excitation system. Voltage control is achieved through automatic voltage regulator (AVR) that regulates the reactive power output and absorption by the generating unit to maintain the desired terminal voltage. If the generator is required to be on power factor control, the AVR will adjust reactive power output to maintain to the desired power factor disregarding the resulting terminal voltage level. These controls refer to exporting sites only. Importing sites are subject to the demand power factor requirements.

5.5.2.5 Synchronisation requirements are discussed in section 5.3. Apart from the

requirements in 5.3.3, the synchronizing control must also ensure that excitation current could only be applied when the generator speed has reached at least 85% of nominal value.

5.5.2.6 Emergency trip control should also be provided for isolating the DG Plant from

the distribution network (breaker at the interface). This ‘push-button’ type control should be located at convenient place for access by TNB operator particularly for emergency purposes.


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55..66 IInntteerrlloocckkiinngg 5.6.1 Operating interlocks are required to prevent undesired operation that could

present safety hazard to operating staff or public. Operating interlocks are categorized into two purposes: Preventive Corrective

5.6.2 Preventive interlock inhibits operation until all required conditions are satisfied.

Examples of preventive interlocks are: Inhibit breaker closing for parallel operation until synchronizing criteria are

met (see 5.6). Remote and local control of circuit breakers – remote control inoperable

when local control is selected Utility and synchronizing breakers as shown in Figures 5.5 and 5.6:

- Synchronizing breaker cannot be closed if utility breaker is opened. - Utility breaker cannot be closed if synchronizing breaker is closed;

5.6.3 Corrective interlocks do not inhibit breaker operation but initiate the additional

remedial operations to enable the desired operation. An example of corrective interlock is illustrated in Figure 5.7. If BR3 is opened then BR2 automatically opened. Loss of Mains intertripping is another example of corrective interlock.

G

From source SW1 BR4 SW2

BR3BR2

SF2

BR1

SW4 (No Load Break Switch)

Bus Reactor

Figure 5.7: Example of corrective interlock


- 85 –


5.6.4 All necessary interlocks must be clearly described in the interface/connection design for the approval of the Distributor.

5.7 Metering 5.7 Metering 5.7.1 Each connection/interface point to the distribution network must have metering

installations unless other arrangements are made with the Distributor. There are two types of metering normally required at the connection/interface point: 1) Revenue metering; and 2) Operational metering. This section provides only general guidelines on metering requirements. For detailed requirements, the Metering Code adopted by the Distributor should be referred to.

5.7.2 For the purposes of revenue metering, the following quantities are to measured:

Active power delivered to the Distributor (kW or MW); Reactive power delivered to the Distributor (kVAR or MVAR); and Energy delivered to the Distributor (kWh or MWh).

Where there is a possibility of power being supplied from the distribution system to the DG Plant the following revenue metering are also required: Active power consumed by the DG Plant (kW or MW); Reactive power consumed by the DG Plant (kVAR or MVAR); and Energy consumed by the DG Plant (kWh or MWh).

5.7.3 In the case of DG Plant, it is usual for the DG Developer to install all the meters

and associated current transformers, voltage transformers, panel and wiring at the connection/interface point in accordance with the requirements of the Distributor. The Distributor shall later maintain the metering installation including any required meter accuracy instrument transformers.

5.7.4 Check meters will normally be used on connection/interface point where the

monthly active energy passing through is above 50,000 kWh or where a maximum demand exceeds 7.5 MW and with reactive check meters being installed where reactive energy passing through exceeds 250,000 kWh or as otherwise determined by the Distributor. Check meters are to be used to provide metering data validation, substitution or estimation when the main revenue meters are suspected to have malfunctioned.

5.7.5 The metering installation may consist of combinations of voltage transformers,

current transformers, secure and protected interconnecting wiring, meter, data logger, communication interface equipment, alarm circuit, test links, and other appurtenances as determined by an Agreement or the Distributor’s Standard.

5.7.6 The followings are requirements for metering accuracies of active energy ( kWh )

meters for different range of active energy passing through interface/connection point: 1) Between 50,000kWh and 250,000kWh:

Main and check meters of class 2.0 with ±2% accuracy and allowable error of ±4%


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2) Between 250,000kWh and 5,000,000 kWh: Main and check meters of class 0.5 with ±0.5% accuracy and allowable

error of ±1%. 3) More than 5,000,000 kWh or having maximum demand exceeding 7.5 MW:

Main and check meters of class 0.2 with ±0.2% accuracy and allowable error of ±1%.

5.7.7 The followings are requirements for metering accuracies of reactive energy ( kWh ) meters for different range of reactive energy passing through interface/connection point: 4) Between 50,000kWh and 250,000kWh:

Main meters of class 3.0 with ±3% accuracy and allowable error of ±6%. 5) More than 250,000 kWh or having maximum demand exceeding 7.5 MW:

Main and check meters of class 3.0 with ±3% accuracy and allowable error of ±6%.

5.7.8 The Distributor should routinely test and calibrate revenue meters in accordance

with current prudent utility practices. This would normally include periodic random audits of metering installations to confirm compliance with adopted metering standards.

5.7.9 Operational metering at the interface/connection points include the following:

1) Current reading in ampere (A) for each phase; 2) Voltage reading in kV for each phase-to-phase; 3) Frequency in Hz; and 4) Real and reactive power flows.

55..88 SSCCAADDAA aanndd AAuuttoommaattiioonn 5.8.1 All DG Plant interface/connection point must be equipped with the following

SCADA facilities: Remote Terminal Units (RTU) c/w Marshalling cubicle; and Communication system from DG plant to TNB control centre.

5.8.2 The RTU shall monitor the following:

Frequency (Hz); Voltage (Volts); Current (Amps); Real Power Energy flow (kW or MW); Reactive Power Energy flow (kVAR or MVAr); and Energy meters. Breaker Status Relay indications, where appropriate.

Where appropriate, derived values, for example real power from voltage and current phasors would be acceptable.

5.8.3 If remote control of switches that are in the jurisdiction/area of responsibility of

TNB are required to be installed at TNB’s control centre, this shall be able to be executed via the RTUs. RTU installed must be able to communicate with TNB


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Master System using IEC 60870-5-101 TNB’s matrix or protocol determines by TNB.

55..99 CCoommmmuunniiccaattiioonnss 5.9.1 The communication system between the DG Plant interface/connection point

where the RTU is located and TNB control centre should be dedicated and reliable communication network. The mode of communication to be used should depend on the location of the DG Plant, capacity of the generating units and/or distance of the DG Plant to the nearest TNB main intake substation (PMU or PPU).

5.10 Network Reinforcements5.10 Network Reinforcements 5.10.1 The connection of the DG Plant to the distribution network may require network

reinforcement to be carried out. During the ‘Preliminary System Study’ stage, the Distributor must ensure that the connection of the DG Plant and its proposed quantum of power injection to the distribution would not result in violation of the design criteria as discussed in chapter 3. The followings are typical criteria applied by the Distributor at the ‘Preliminary Planning Study’: 1) Normal steady-state voltage limits; 2) Contingency voltage limits; 3) Thermal overload limits of network element; In addition to the above, the following criteria are also applied: 4) Voltage step limit; 5) Fault level 90% limit; 6) Losses to be below without DG Plant; and 7) SAIDI Reliability index is not worst of without DG Plant. In carrying out the above assessments, current practice is to assume that the DG unit is operating at unity power factor and that three load levels are used for assessments, namely: peak, intermediate and light loads.

5.10.2 If any of the above criteria is not met or too restrictive, three options could be applied: 1) Use of voltage and or turbine controls; 2) Reduced active power generation from the DG Plant, that is, lower than what

is proposed by the DG Developer; or 3) Network reinforcements which may include any of the following or their

combinations: Additional feeders Additional switches/breakers Shunt capacitors Series capacitors Shunt reactors Series reactors Different voltage levels.


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5.10.3 The cost of connection should comprise of two components: Circuit from interface/connection point to a point in the Distributor’s existing

network; and Any of the network reinforcements as listed above.

5.10.4 With respect to network losses, the current practice is to use the following

options to ensure that losses due to the connection of the DG will not be greater than losses without the DG: Network reinforcement; or/and Reduce DG Plant export to the distribution network.


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CChhaapptteerr 66:: GGlloossssaarryy

66..11 GGeenneerraall TTeerrmmss 6.1.1 In this guidebook, the following general terms, words and expressions shall bear

the following meanings: A.C., a.c., AC or ac Alternating current. Act The Electricity Supply Act 1990 (Act 447) including

any modification, extension, or re-enactment the of and any subordinate legislation made there under.

Active Energy The electric energy produced, flowing, or supplied by

an electric circuit during a time interval, being the integral with respect to time of the instantaneous power, measured in units of watt-hours (wh) and multiples thereof.

Active Power The product of voltage and the in-phase component

of alternating current measured in units of watts and multiples thereof.

Adequate / Adequacy The ability of the distribution system to provide

acceptable and continuous supply of electricity while remaining within component ratings during normal or contingency conditions.

Apparatus All items of equipment in which electrical conductors

are used, supported, or which may form a part. Apparent Power The product of voltage and alternating current

measured in units of volt amperes. Is also the square root of the sum of the squares of the active power and the reactive power.

Automatic Reclose Equipment In relation to a transmission line or distribution line,

the equipment which automatically recloses the relevant line’s circuit breaker(s) following their opening as a result of the detection of a fault in the transmission line or the distribution line (as the case may be).

Automatic Voltage Regulator A system for controlling generating unit or

transformer voltage within set limits.


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Black Start The procedures necessary for a recovery from a Total Shutdown or Partial Shutdown.

Black Start Capability The ability of Embedded generation to start-up from a

stopped or cold state, without a source of external power, and to energize part of the Distribution network upon instruction from the Distributor.

Busbar A common connection point in a power station

switchyard or a transmission/distribution network substation.

Capacitor Bank Electrical equipment used to generate reactive power

and support voltage levels on distribution lines in periods of high load.

Capacity The net MW and MVAr capacity of generating unit, or

any other transmission/distribution apparatus at a particular time, to supply electrical energy.

Caution Notice A notice conveying a warning against interference. Central Dispatch The process of Scheduling and issuing direct

operating instructions by the Grid System Operator. Centrally Dispatched Generator A Genset of a capacity of 10 MW and above

subject to Central Dispatch under the Grid Code. Check Meter A meter, other than a revenue meter, used as a

source of metering information. Check Metering Installation A metering installation used as the source of metering

information for validation in the settlements process. Connect, Connected, Connection To form a physical link to or through a

transmission or distribution network. Connection Agreement An agreement between a Distributor and Other Entity

or other person by which the Other Entity or other person is connected to the transmission or distribution network and/or receives transmission or distribution services.

Connection point The agreed point of supply between a Distributor and

other Entity. Consumer See Customer.


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Contingency In respect of a transmission or distribution network, a sequence of related events which result in outages of one or more transmission or distribution elements.

Control Center A location used for the purpose of control and

operation of the Grid System or a Distributor’s distribution network.

Control System Means of monitoring and controlling the operation of

the power system or equipment including generating units connected to a transmission or distribution network.

Current Harmonics Distortion Is the measure of the departure of the a.c. current

waveform from sinusoidal shape, i.e., caused by the addition of one or more harmonics to the fundamental component.

Current Transformer (CT) A transformer for use with meters and/or protection

devices in which the current in the secondary winding is, within prescribed error limits, proportional to and in phase with the current in the primary winding.

Customer A person who engages in the activity of purchasing

energy supplied through a transmission or distribution system; and the final and user of energy.

Data Collection System All equipment and arrangements that lie between the

metering database and the point where the metering data enters the public telecommunications network and used for calculations of payments due to or from Other Entities.

Data Logger A device that collects energy data, packages it into

30 minute intervals (or sub-multiples), holds a minimum of 35 days at data, and is capable of being accessed electronically via the data collection system. This device may be a separate item of equipment, or combined with the energy measuring components within one physical device.

Demand The demand of MW and MVAr of electricity (i.e., both

Active and Reactive Power ), unless otherwise stated, at a particular time or during a time period.

Demand Control Any or all of the following methods of achieving a

Demand reduction; (a) Customer Demand Management initiated by Distributors; (b) Customer voltage reduction initiated by Distributor (other than following an instruction from the Independent Grid


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System Operator); (c) Customer Demand reduction by Disconnection initiated by Distributors (other than following an instruction from the Independent Grid System Operator); (d) Customer Demand reduction instructed by the Independent Grid System Operator; (e) Automatic Low Frequency Demand Disconnection; (f) emergency Manual Demand Disconnection.

Dispatch The issue by the Independent Grid System Operator

of instructions for Generating plant to achieve specific Active Power ( and in relation to Generating plant, reactive Power, or target voltage ) levels within their Generation Scheduling and Dispatch parameters and by stated times.

Disconnection, Disconnect The operation of switching equipment or other action

so as to prevent the flow of electricity at a connection point.

Discrimination The quality where a relay or protective system is

enable to pick out and cause to be disconnected only the faulty Apparatus.

Distribution Line A power line, including underground cables, that is

part of a distribution network. Distribution Losses Electrical energy losses incurred in distributing

electricity over a distribution network. Distribution Network A system comprising of electrically connected

equipment or elements that produce, transport, transform, control, and consume electrical power at medium and low voltage levels.

Distribution System The system consisting ( wholly or mainly ) of electric

lines which are owned and operated by Distributor and used for the distribution of electricity from Grid Supply points or Generating Units or other entry points to the point of delivery to Customers or Other Distributors.

Distribution System Control Center The facility used by a Distribution System Operator

for directing the minute to minute operation of the relevant distribution system.

Distribution System Operator A person who is responsible for the management of

any portion of a distribution system or for directing its operations.


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Distributor A person who is licensed Under Section 9 of the Act and is connected to the Grid System and distributes electricity for the purpose of enabling a supply to be given to any premises.

Disturbance Any perturbation to the electric system caused by the sudden loss of generation or interruption of load.

Earthed Means connected to the general mass of earth by

means of a suitable buried metal pipe or plate or other means approved by the Director General.

Earthing A way of providing a connection between conductors

and earth by an Earthing Device which is either: (a) immobilized and locked in the earthing position. Where the Earthing Device is locked with a Safety key, the Safety Key must be secured in a key Safe and the Key safe key must be retained in safe custody, or (b) maintained and/or secured in position by such other method which must be in accordance with the Local Safety instructions of the independent Grid System Operator or that Distributor, as the case may be.

Earthing Device A means of providing a connection between a

conductor and earth being of adequate strength and capability.

Embedded Generating Unit A generating unit connected within a distribution

network and not having direct access to the transmission network. This includes an Embedded Generator connected to its own Network which Network is interconnected with the Distributor’s network either directly or through a step up transformer.

Embedded Generation The production of electrical power by converting

another form of energy in a generating unit that is connected to the distribution system.

Embedded Generator A Generator or Customer who owns, operates, or

controls an embedded generating unit. Energy ( Active and Reactive ) Active energy is the electrical energy produced,

flowing or supplied during a time interval measured in units of watt-hours (Wh) or standard multiples thereof. Reactive energy is the energy produced, flowing or supplied during a time interval measured in units of volt-ampere-hours reactive, (varh) or standard multiples thereof.


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Energy Data The information that results from the measurement of the flow of electricity in a power conductor. The measurement is carried out at a metering point.

Event An unscheduled or unplanned occurrence on or

relating to a system including faults, incidents, and breakdown.

Forced Outage An outage caused by emergency condition directly

associated with a component that requires to be taken out of service immediately, either automatically or as soon as switching operation can be performed, or an outage caused by improper operation of equipment or human error.

Frequency the number of alternating current cycles per second

(expressed in hertz (Hz)) at which alternating current electricity is operating.

Generation the production of electrical power by converting

another form of energy in a generating unit. Generating Plant See generating system. Generating System A system comprising one or more generating units. Generating units Any apparatus which produces electricity. Generator A person who is licensed Under Section 9 of the Act

and is connected to the Grid System and generates electricity for the purpose of enabling a supply to be given to any premises. Also, any apparatus which generates or produces AC electrical power, including Active and/or Reactive Power.

Grid Code The Malaysian Grid Code, as from time to time,

revised in accordance with the License by the Malaysian Grid Code Committee.

Grid Entry Point A point at which a Generating Unit, as the case may

be, which is directly connected to the Grid System. Grid Supply point A point of supply from the Grid System. Grid System The system consisting (wholly or mainly ) of high

voltage, namely 500kV, 275kV, 132kV, and 66kV transmission lines owned by a Transmittor and operated by the Grid System Oerator and used for the transmission of electricity from one power station to a substation or to another power station or


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between substations or to or from any External Interconnection, and includes any Plant and Apparatus and meters owned or operated by the Transmittor in connection with the transmission of electricity.

Interruption The loss of service to one or more customers or other

facilities and is the result of one or more component outages, depending on the system configuration.

High Voltage (HV) A voltage equal to or greater than 50kV. Insulated Means covered or protected by insulating material. Interconnection, Interconnector, Interconnect, Interconnected A transmission or distribution line or group of

transmission or distribution lines that connects the transmission or distribution networks in adjacent regions.

Isolating Device A device for achieving Isolation by adequate physical

separation or sufficient gap for voltage level involved. License Any license granted by the Energy Commission of

Malaysia. Licensee Any person, who is granted a license for generation,

transmission, distribution, or combination thereof to supply electricity to any premises, by the Director General of the Department of Electricity and gas Supply.

Load To Active, Reactive, or Apparent Power, as the

context requires, generated, transmitted, distributed or consumed.

Loading The apparent power level at which each element of

the network is operated. Load Forecast Estimate of future consumption or generation of

electricity in MW, MVAr, MWh, MVARh. Load-shedding Reducing or disconnecting load from the power

system. Low Frequency Relay Has the same meaning as Under Frequency Relay. Low Voltage or LV A voltage level less than 1000 volts or 1 kV.


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Medium Voltage or MV A voltage equal to or exceeding 1kV but not exceeding 50 kV.

Meter A device complying with Standards which measures

and records the production or consumption of electrical energy and/or demand.

Metering Recording the production or consumption of

electrical energy. Metering Data. The data obtained from a metering installation, the

processed data or substituted data. Metering Point The point of physical connection of the device

measuring the current in the power conductor. Metering System The collection of all components and arrangements

installed or existing between each metering point and the metering database.

MV Distribution Network The various circuit and Apparatus owned by the

Distributor operating at primary phase to phase voltages above 1kV and less than 50kV.

Momentary Interruption An interruption having a duration limited to the period

to restore service by automatic or supervisor-controlled switching where an operator is immediately available.

Nominal Frequency Means 50Hz frequency on Grid System or Distribution

System. Non-Scheduled outage See forced outage. Operating Criteria Refers to a set of measures for assessing the

performance of the distribution system during the operation stage.

Operation A scheduled or planned action relating to the

operation of a System. Operation Criteria see operating criteria Out of Synchronism The condition where a System or generating unit

cannot meet the requirements to enable it to be synchronized.

Outage Describes the state of the component when it is not

available to perform the intended function due to


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some event associated with that equipment. Duration will count toward computation of SAIDI.

Planning Criteria See planning and design criteria Planning and Design Criteria Refers to a set of measures for assessing the

performance of the distribution system during the planning stage.

Planned Outage See scheduled outage. Point of Interface A designated boundary of owner ship between the

Distributor and the Other Entities. Power Factor The ratio of Active Power to Apparent Power. Power Quality It is the measure of the purity of supply voltage and

current waveforms. Power Quality Characteristics In this guidebook the term refers to the measures

used for determining the purity of the a.c. voltage of current waveforms.

Power Station An installation comprising one or more Generating

Units (even where sited separately) owned and/or controlled by the same Generator which may reasonably be considered as being managed as one Power Station.

Power System The electricity power system of Malaysia including

associated generation and transmission and distribution networks for the supply of electricity, operated as an integrated arrangement.

Protection The provisions for detecting abnormal conditions on a

system and initiating fault clearance or actuating signals or indications.

Protection Apparatus A group of one or more Protection relays and/or logic

elements designated to perform a specified protection function.

Protection System A system, which includes equipment, used to protect

facilities from damage due to an electrical or mechanical fault or due to certain conditions of the power system.

Prudent Utility practices With respect to the Distributor, means the exercise of

that degree of skills, diligence, prudence and foresight consistent with the applicable acts,


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regulations, condition of license, standards, codes and the Distributor’s owned standards and practices.

Reactive Energy A measure, in var hours (varh) of the alternating

exchange of stored energy in inductors and capacitors, which is the time-integral of the product of voltage and the out-of-phase component of current flow across a connection point.

Reactive Power The product of voltage and current and the sine of the

phase angle between them measured in units of volt amperes reactive. The rate at which reactive energy is transferred.

Reliability In the context of a distribution system is a measure of

availability of adequate and secure supply to the Customers

Revenue Meter The meter that is used for obtaining the primary

source of metering data for billing purposes. Revenue Metering Installation A metering installation used as the primary source of

metering data. Safety Precautions Isolation and/or Earthing Safety Rules The rules of a Generator or Distributor that seek to

ensure that persons working on Plant and/or apparatus to which the rules apply are safeguarded from hazards arising from the System.

SAIDI System Average Interruption Duration Index for all

types of interruptions. This distribution reliability index sometimes referred to as customer Minutes or Customer Hours is designed to provide information about the average time the customers are interrupted.

SAIFI System Average Interruption Frequency Index for

sustained interruption. The objective of this distribution reliability index is to provide information about the average frequency of sustained interruptions per customer over a predefined area.

Schedule Outage An outage that results when a component is

deliberately taken out of service at a selected time, usually for the purpose of construction, preventive maintenance or repair.

Security Means security of supply


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Security of Supply The ability of the distribution system restore supply to Customers following momentary or temporary interruptions.

Single Contingency In respect of a transmission or distribution network, a sequence of related events which result in the removal from service of one transmission or distribution line, or transformer. The sequence of events may include the applications and clearance of a fault of defined severity.

Substation A facility at which two or more lines are switched for

operational purposes. May include one or more transformers so that some connected lines operate at different nominal voltages to others.

Supply Characteristics In this Guidebook the term refers to power quality

characteristics, that is, the measure of the purity of the voltage or current waveforms.

Supply Performance Refers to each of the performance measures

contained in the planning or operating criteria. Sustained Interruption It is any supply interruption to one or more customers

not classified as momentary or temporary. Supply Security See Security of Supply Synchronized The condition where an incoming Generating Unit or

System is connected to the bus bars of another System so that the Frequencies and phase relationships of that Generating Unit or System, as the case may be, and the System to which it is connected are identical.

System Any distributor or Generator’s System or the Grid

System, as the case may be. System Constraint A limitation on the use of System due to lack of

distribution capacity or other System conditions. System Operator A person whom a Distributor has appointed as its

agent to carry out some or all of its rights and obligations.

Tap-changing Transformer A transformer with the capability to allow internal

adjustment of output voltages which can be automatically or manually initiated and which is used as a major component in the control of the voltage of the transmission and distribution networks.


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Tariff Metering Meters, associated CTs and VTs, metering protection equipment, data collection, wiring and other devices or part thereof which are part of the Active Energy or Reactive Energy measuring equipment at a specific Connection Point.

Temporary Interruption An interruption having a duration limited to the period

required to restore service by manual switching at locations where operators are not immediately available.

Total Harmonic Distortion The departure of a wave form from sinusoidal shape,

that is caused by the addition of one or more harmonics to the fundamental, and is the squares of all harmonics expressed as a percentage of the magnitude of the fundamental frequency.

Transformer A plant or device that reduces or increases the

voltage of alternating current. Transformer Tap Position Where a tap changer is fitted to a transformer, each

tap position represents a change in voltage ratio of the transformer which can be manually or automatically adjusted to change the transformer output voltage. The tap position is used as a reference for the output voltage of the transformer.

Transmission Grid A network operating at nominal voltages of 50 kV and

above. Transmission or Distribution system A transmission or distribution system that : (1) is used

to convey, and control the conveyance of, electricity to Customers (whether wholesale or retail); and (2) is connected to another such system.

Transmission Plant Apparatus or equipment associated with the function

or operation of a transmission lone or an associated substation or switchyard, which may include transformers, circuit breakers, reactive plant and monitoring equipment and control equipment.

Tripping The opening of a circuit breaker as a direct and

normally immediate consequence of the operation of a protection relay or advice.

Unbalanced Load The situation where the Load on each phase is not

equal.


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Under Frequency Relay An electrical measuring relay intended to operate when its characteristic quantity (Frequency) reaches the relay settings by decrease in Frequency.

Voltage Dip Transient reduction in voltage magnitude measured as the percentage or per unit reduction of the voltage magnitude to the nominal voltage magnitude.

Voltage Harmonic Distortion It is the measure of the departure of the a.c. voltage

waveform fro, sinusoidal shape, that is caused by the addition of one or more harmonics to the fundamental.

Voltage Sag Transient reduction in voltage magnitude measured

as the percentage or per unit remaining voltage magnitude to nominal voltage magnitude.

Voltage Sensitive Load A load that will mal-operate on transient distortion of

supply voltage sinusoidal waveform. Voltage transformer (VT) A transformer for use with meters and/or protection

devices in which the voltage across the secondary terminals is proportional to and in phase with the voltage across the primary terminals.

66..22 OOtthheerr TTeerrmmss 6.2.1 The following additional or alternative terms are mainly used in TNB’s

connection and commercial agreements and may be used as reference. “Agreement” This Renewable Energy Power Purchase Agreement and the

appendices, schedules and exhibits hereto as may be amended, deleted and/or changed from time to time by prior written consent of both Parties;

“Billing Period” The period (i) commencing on the Commercial Operation Date of the Facility and ending on the last calendar day of that month and thereafter (ii) between the first calendar day and the last calendar day of every calendar month throughout the Term for the Facility; and (iii) the period beginning on the first day of the month in which the Term expires and ending on the day the Term expires;

“Business Day” Any day on which commercial banks are authorized or required to be opened in Kuala Lumpur, Malaysia;

“Change-in-Law” Any of the following events occurring after the Effective Date as a result of, or in connection with, any action by any


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Governmental Entity, court or tribunal :

(a) A change in or repeal of an existing Law;

(b) An enactment or making of a new Law.

(c ) A change in the manner in which a Law is applied or

in the interpretation thereof.

(d) The imposition of a requirement for a new Governmental Authorization ; or

(e) A change in the terms and conditions of a Governmental Authorization.

“Commencement Date”

The date on which construction work on the Facility is to begin and written notice of such date shall be given, being not less than thirty (30) days prior to actual commencement of construction at Site, by The Seller to TNB;

“Commercial Operation Date” (COD)

The date on which (i) all of the conditions precedent set forth in Clause 4 shall have been satisfied or waived by TNB and (ii) shall have established its export capacity of XXX MW;

“Communication Facilities”

Means all of the facilities described under Appendix E as determined by TNB under Clause 12.6 to be necessary, in accordance with Prudent Utility Practices, to enable the Control Centre to communicate and Despatch the Facility;

“Control Centre” The Control Centre of TNB as designated in writing by TNB from time to time (but not more than one at any one time) as being the sole TNB control centre, for the Facility;

“Default Rate” A rate equal to two per centum (2%) above the base lending

rate then in effect at the principal office of MayBank Berhad, or its successors in title.

“Delivered Power” For the purpose of this Agreement shall mean the rate at

which electrical energy is delivered by the Facility to TNB at the Interconnection Point and is measured in Kilowatts;

“Despatch” Means the issuance of an oral or written instruction

communicated to The Seller by the Control Centre directing

the Facility to commence, increase, decrease or cease the


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generation and delivery of electrical energy into the TNB

System, in accordance with the provisions of this Agreement;

“EC” The Energy Commission, a statutory body established under

the Energy Commission Act 2001 and any successors

thereof;

“Effective Date” The date of the execution and delivery of this Agreement by

The Seller and TNB and that all corporate authorisations which are required to have been obtained by the Parties in connection with the execution and delivery of this Agreement have been obtained and are in full force and effect and a statement in writing to that effect has been submitted to each Party;

“Emergency Condition”

A condition or situation that, in TNB’s reasonable judgment, based on Prudent Utility Practices (i) presents an imminent physical threat of danger to life, health or property, or (ii) threatens the safety, reliability or security of the TNB System, or (iii) could reasonably be expected to cause a significant disruption on the TNB System or (iv) could reasonably be expected to adversely affect TNB’s ability to meet its obligations to provide safe, adequate and reliable electricity service to its customers, including other utilities with which TNB System is interconnected;

“Energy Payment” For each Billing Period, the payment to be made by TNB to

The Seller for electrical energy delivered to the Interconnection Point and received by TNB during such Billing Period;

“Event of Default” The occurrence of any of the events described in Clause 18 hereof;

“Facility” The whole of the plant installation with the nominal capacity of YYY MW as stipulated in Recital A, with all necessary plant, buildings and land in connection therewith, electricity connection and consuming apparatus, if any as per Appendix A of this Agreement;

“Force Majeure Event”

Any event, condition or circumstance described in Clause 17


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hereof;

“Forced Outage” Any interruption (excluding an interruption due to a Force

Majeure Event) of the Facility then in effect that is not the result of (i) a Scheduled Outage, Maintenance Outage or Major Overhaul Outage, or (ii) a condition caused by TNB or the TNB System;

“Fossil Fuel”

A hydrocarbon deposit that consists of remains of animal or

vegetable life from past geologic ages that is now in a

combustible form which is suitable for use as fuel; for

example, oil, coal, or natural gas;

“Government Authorization”

Any authorization, consent, licence, concession, permit, waiver, privilege, exemption and/or approval from, or filing with, or notice to any Government Entity;

“Government Entity”

Any national, state or local legislature of the government of Malaysia and any ministry, department, instrumentality, agency, authority or commission of the government of Malaysia or any other similar entity, including Energy Commission;

“Grid Code” Means the Malaysian Grid Code, as amended from time to time in accordance with applicable Law;

“Independent Engineer”

Shall mean the reputable consulting engineering firm or professional engineer retained by The Seller and approved by The Seller’s financiers as the Independent Engineer of The Seller in connection with the design and construction of the Facility and Interconnection Facilities;

“Initial Operation Date” (IOD)

The first date on which electrical energy is generated and delivered from the Facility to the Interconnection Point;

“Interconnection Facilities”

All of the facilities, as specifically described in Appendix D, to be necessary, in accordance with Prudent Utility Practices, to enable TNB to receive electrical energy from the Facility and to maintain the stability of the TNB System, including the sub-station and/or switching station, all transmission lines, transformers and associated equipment, communications equipment, relay and switching equipment, circuit breakers and other protective devices and safety equipment, telecommunications equipment and the metering equipment, wherever located;


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“Interconnection Point”

The physical points where the Facility and the TNB System are connected, as shown in Appendix D, or such other point or points as the Parties may agree;

“KTAK” Ministry of Energy, Water and Communication (formerly known as Ministry of Energy, Communications and Multimedia);

“kW” Kilowatt;

“kWh” Kilowatt-hour;

“Law” Any (i) law, legislation, statute, act, rule, order, treaty, code or regulation, or (ii) legally binding announcement, directive or published practice or any interpretation thereof, enacted, issued or promulgated by any Governmental Entity or court or tribunal;

“Licence” The licence granted to The Seller under the Electricity Supply Act, 1990 to enable The Seller to own and operate the Facility and to operate electricity generating capacity and supply electric energy to TNB therefrom;

“Maintenance Outage”

A planned interruption or reduction of the electricity generating capability of the Facility that (i) is not a Forced Outage, Scheduled Outage or a Major Overhaul Outage, (ii) has been co-ordinated with TNB in accordance with Clause 12 and (iii) is for the purpose of performing work on the Facility, which work could be postponed by at least seventy two (72) hours, but in the opinion of The Seller should not be postponed until the next Scheduled Outage;

“Major Overhaul Outage”

A planned interruption or reduction of the electricity generating capability of the Facility that is needed for a major overhaul of any generating unit or any associated equipment of the Facility that has been co-ordinated with TNB in accordance with Clause 12, and is in accordance with Prudent Utility Practices and manufacturer’s recommendations;

“The Seller” The Seller Sdn. Bhd., a company incorporated under the laws of Malaysia, including its successors in title and permitted assigns;

“MW” Megawatt;

“Off-Peak Hours” Shall mean the periods between 0000 hours to 0900 hours


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and between 1700 hours to 2400 hours of each day;

“Operations Committee”

Shall mean the operations committee described in Clause 11.2 hereof;

“Peak Hours” Shall mean the period between 0900 hours to 1700 hours of each day;

“Parties” TNB and The Seller and a reference to a “Party” means either TNB or The Seller as the case may be;

“Person” Means any individual, corporation, partnership, joint venture, trust, unincorporated organisation or Government Entity;

“Power System Study” (PSS)

Impact assessment study of the operations of The Seller’s Facility on the TNB System based on TNB requirements as stipulated in the TNBD MV Technical Guidebook;

“Project” The development, design, financing, insurance, procurement, construction, installation, testing, commissioning, ownership, operation, management and maintenance of the Facility including ancillary buildings and associated activities related to this project, as more specifically described in Appendix A, and any modification thereof;

“Prudent Utility Practices”

Means the practices, methods and standards generally followed by the electricity supply industry in Malaysia, during the applicable period, with respect to the design, construction, testing, operation and maintenance of the electricity generating, transmission and distribution equipment of the type used by the Facility and the TNB System, which practices, methods and standards generally conform to applicable Laws, the operation and maintenance standards recommended by the equipment suppliers and manufacturers of the Facility and the TNB System, the International Electricity Commission standards, the Grid Code and any other applicable electricity code approved by EC;

“Renewable Energy Fuel”

Any means of fuelling or driving the Facility as permitted

under the Small Renewable Energy Power (SREP)

Programme guidelines, being in each case a non-fossil fuel;

“Ringgit” (“RM”)

The lawful currency of Malaysia;

“Scheduled The scheduled date for the commencement of commercial


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Commercial Operation Date”(SCOD)

operation of the Facility as specified in Clause 5.4;

“Scheduled Outage”

A planned interruption of the electricity generating capability of the Facility that (i) is not a Maintenance Outage or Major Overhaul Outage, (ii) has been co-ordinated in advance with TNB with a mutually agreed start date and duration pursuant to Clause 12 and (iii) that is required for the inspection, preventive maintenance or corrective maintenance, repair or improvement of the Facility;

“Sen” The lawful currency of Malaysia;

“Site” The parcels of land upon which the Facility is to be constructed and located, and as more specifically described in Appendix A hereto;

“Small Renewable Energy Power Programme”

A programme initiated by KTAK on 11.5.2001 which is aimed at supporting the Government’s desire to develop Renewable Energy (RE) as an alternative fuel resource;

“Term” The period of this Agreement as specified in Clause 3.1 hereof;

“Test Energy” The electrical energy associated with the start-up and commissioning of the Facility prior to the relevant Commercial Operation Date, and metered at the Interconnection Point;

“TNB” Tenaga Nasional Berhad, a company incorporated under the laws of Malaysia, including its successors in title and permitted assigns;

“TNB Licence” Means the licence required and obtained by TNB or any extension thereof pursuant to Section 9 of the Electricity Supply Act 1990;

“TNB MV Interconnection Guidebook”

Means the latest edition of the guidebook for other users to be interconnected to the TNB Medium Voltage (MV) Distribution network titled “A Guidebook of the Technical Requirements for the Interconnection of A User’s Network to TNB’s MV Distribution Network”;

“TNB System” The bulk power network controlled or used by TNB for the purpose of generating electricity, and transmitting and distributing electricity to TNB’s customers.


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77.. AAppppeennddiixx AA:: SSuummmmaarryy ooff TTNNBB PPoowweerr SSyysstteemmss

77..11 IInndduussttrryy SSttrruuccttuurree

7.1.1 A Brief History of Electricity Industry in Malaysia Prior to 1950’s, the electricity supply industry in Malaysia was dominated by privately owned companies operating in their respective franchise areas and regulations were minimal. As the demand of electricity grew, a government utility, the Central Electricity Board (CEB) was established in 1949 to acquire many small privately owned companies while the major companies continued to operate and being regulated by the Government. In 1965, the CEB is renamed as the National Electricity Board (NEB, well-known in Malay as LLN) with added responsibility to ‘nationalise’ the private suppliers. Nationalisation policy resulted in acquisition of privately owned utilities. In 1987, the privatisation of the electricity supply industry was initiated and in 1990 the NEB was corporatised as Tenaga Nasional Berhad (TNB).

7.1.2 Electricity Industry Reform In late 1980’s the Government’s privatization policy marked the beginning of electricity industry reforms of 1990’s that is still undergoing at the present. The government has created competition, to a certain extent, in generation by licensing private sector to build, own and operate power generating plants as independent power producers (IPPs) and supply electricity through negotiated power purchase agreements (PPA). Since 1997, TNB has also been gradually divesting their interests in thermal power plants to private investors and until 2004, there are 23 IPPs have been given licenses to operate in Peninsular Malaysia.

7.1.3 Renewable Energy (RE) and The Small Renewable Energy Programme (SREP) The Government of Malaysia has embarked on programmes to promote efficient use of energy as well as to increase the use of renewable energy (RE), particularly biomass from the agricultural sector for power generation in line with the launch of the revised Energy Policy in 2001. This is known as ‘RE As 5th Fuel’. The aim of the RE Programme is to generate 5% of the country’s electricity from renewable energy resources by year 2005. In addition, The Small Renewable Energy program (SREP) was launched in 2001, aiming at encouraging private sector to use renewable energy resources, especially oil palm waste from the palm oil industry, to generate electricity to the local distribution network.

7.1.4 Current structure of electricity industry In the current structure, there are three main electricity utilities in Malaysia: TNB in Peninsular Malaysia; Sabah Electricity Sdn Bhd (SESB) in the State of Sabah; and, SESCo in the State of Sarawak. The Government and related government-owned companies/entities own approximately 75% of TNB. SESB is owned 80% by TNB and 20% the Sabah State Government. The major shareholder of SESCo is the Sarawak State Government. The three


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main utilities are vertically integrated entities undertaking generation, transmission, distribution and supply of electricity in the Peninsular Malaysia, Sabah and Sarawak respectively. Until recently, besides the three main utilities, twenty-three IPP licenses, one transmission licenses and a number of merchant co-generations licenses have been granted. Besides these, about two thousands self-generation licenses have been issued to industrial and commercial entities that generate electricity for their own use. In addition, three mini utilities have been established to provide high quality supply for high-tech semiconductor and petro-chemical industrial entities. The current structure of electricity supply industry in Peninsular Malaysia and Sabah and Sarawak are illustrated in figures 7.1(a) and 7.1(b) respectively.

Figure 7.1(a): The Structure of Electricity Supply Industry in Peninsular Malaysia



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Figure 7.1(b): The Structure of Electricity Supply Industry in Sabah and Sarawak

7.1.5 Regulation and Licensing Malaysia has successfully privatized the electricity supply industry since early 1990s. However, after in depth studies, Malaysia did not join the other countries in the ‘dash for deregulation’. The power sector of Malaysia remains as regulated industry with vertically integrated utilities. In 1990, The Department of Electricity Supply (DES) was formed under the Electricity Supply act 1990 as the industry and safety regulator of the electricity supply in Peninsular Malaysia and Sabah. However, in Sarawak the State Electricity Ordinance is in force providing the State Electrical Inspectorate with the legal power for electricity supply regulatory functions. In 2001, the DES was known as the Energy Commission (EC) of Malaysia - established under the Energy Commission Act 2001 - whose functions include:

To promote competition in the electricity industry To issue and enforce licenses To undertake economic, technical and safety regulations To enforce consumer protection codes To ensure compliance with industry codes

The EC reports directly to the Minister and has ‘promotion of competition’ being one of the most important function. Electricity pricing is an item handled Electricity Commission. A balance is required between the market price and the price affordable by majority of the population. Currently, tariff is approved by the highest decision making body in the country where political and socio-economic considerations are of prime importance. Currently, electricity tariff is fixed but varies according to customer groups and voltage level. Energy



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Laws and Regulation that are regulating the electricity industry in Peninsular Malaysia and Sabah are: Energy Commissioning Act 2001 Electricity Supply Act 1990 Electricity Supply Regulation 1994

Figure A.2 illustrates the current structure of institutional and regulatory structure of the industry in Peninsular Malaysia and Sabah

Figure 7.2: Institutional and Regulatory Structure of Electricity Supply Industry in Peninsular Malaysia and Sabah


77..22 PPoowweerr GGeenneerraattiioonn

7.2.1 Generation Entities Power generation in Malaysia is mainly provided by three main electricity utilities: TNB in Peninsular Malaysia; SESB in the State of Sabah; and, SESCo in the State of Sarawak. There are also a number of IPPs operating in the Peninsular Malaysia, Sarawak and Sabah. As in 2002, there are 23 licensed IPPs operating throughout the country.

7.2.2 Generation Mix In 2002, generation mix fuel of TNB and IPP was 75.0% gas, 11.0% coal, 7.1% hydro, 4.5% oil and the remaining others. The total installed generating capacity in Malaysia, as at April 2003, was 15,838MW: 14,221MW in Peninsular Malaysia; 819MW in Sarawak, and; 798MW in Sabah. In Peninsular Malaysia, TNB Generation Division (formerly known as TNB


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Generation and TNB Hidro ), provide approximately 60% of the installed generating capacity. Five IPPs provide the remaining 40%. In Sabah, SESB provides 493MW (62%) of installed capacity with five IPPs providing the remaining 305MW of capacity (38%). In Sarawak, SESCo provides 499MW (61%) of the installed capacity with the other 320MW (39%) being provided by two IPPs. Within the total installed capacity in Malaysia, there is an approximate 30% to 35% reserve margin.

7.2.3 Self Generation and Co-generation In addition to the grid connected generating capacity, there are also a considerable number of self-generation and co-generation power plants in operation Malaysia. The agriculture and timber processing industries in the remote areas of Malaysia operate self-generation power plants to supply their own needs. Large portions of these facilities are using biomass or agricultural waste as fuel. A number of industrial and commercial complexes also operate co-generation power plants to supply both their heat or chilled water requirements and electricity by using natural gas as fuel. There are also several industrial complexes, especially in the petro-chemical sector, using industrial waste heat for generation.

77..33 TTrraannssmmiissssiioonn aanndd PPoowweerr SSyysstteemm OOppeerraattiioonn

7.3.1 Transmission System TNB Transmission Division (known as TNBT) is the transmission network service provider for Peninsular Malaysia and has a monopoly on the transmission of electricity in Peninsular Malaysia. Similarly, SESCo and SESB have monopolies on transmission in Sarawak and Sabah respectively. TNB Transmission Division manages and operates the 132kV, 275kV and 500kV transmission systems that form an integrated network - the National Grid as illustrated in figure 7.3. The Grid can be considered as the backbone of the electricity industry in Peninsular Malaysia. TNB’s National Grid system spans the whole of Peninsular Malaysia, connecting power stations owned by TNB and IPPs to customers. The grid is interconnected in the North to Thailand’s transmission system (operated by the Electricity Generating Authority of Thailand, EGAT) via a HVDC interconnection with a transmission capacity of 300MW and a 132kV AC overhead line with maximum capacity of 80MW. In the South, the National Grid is connected to Singapore’s transmission system at Senoko via 2 X 230kV submarine cables with a firm transmission capacity of 200MW. Standard nominal voltages for transmission system are 500kV, 275kV and 132kVas illustrated in figures 7.4 and 7.5. Sub-transmission voltage system used to interface between bulk power transmission system and distribution system. In TNB system, the 132kV network is used to deliver power from National Grid to distribution substations.


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Figure 7.3: TNB Power System Configuration

Figure 7.4: TNB System Voltage Configuration



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Figure 7.5: Typical Supply Scheme

7.3.2 Power System Operation Operation of Grid is a process and procedure of coordinating the supply and demand of electricity through the Grid, which is inherently complex. In order to ensure reliable operation of the power Grid, several activities involving load forecasting, planning and investment, operational planning and control operation of The National Load Dispatch Centre (NLDC) must be carried out accurately and efficiently.

7.3.2.1 Load forecasting In power system operation, short-term load forecasting is a starting point of maintaining the balance between generation and demand. In TNB, both long-term and short-term load forecasting are carried out by a group of specialists in the system planning unit. The forecast would then be used by the Production Planning unit to schedule and commit generating units in the system.

7.3.2.2 Planning & Investment Apart from operating the existing system economically and securely, power system operation function may from time to time be involved in planning of the network involving investment of capital to enhance system reliability. As the system changes and/or different contingencies applied, operation engineers may find that the network may not be able to operate securely and that can only be corrected through installation of additional equipment or facilities. In such cases, the investment requirements are determined by operation function as opposed to usual cases by the network system planning function. In TNB,



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operation function cooperates and coordinates closely with the planning function to identify short- to medium term plans to improve system reliability. Otherwise most network investment plans including improvement of reliability are carried out by the network planning group.

7.3.2.3 Operational planning Operational planning comprises of activities carried out for the purposes of preparing system operators, power plant operators and other users of the network including maintenance crew on how to operate the network – its components and controls - in the most economical manner while keeping security as the top priority. Demand forecast is the fundamental input for operational planning – both medium terms and short terms. Activities of operational planning include; plant availability forecasting, coordination of generation and transmission outages, fuel transport and storage requirements plans, and to advice control operators on real-time control particularly on responses to contingency situations. In TNB, Operational Planning Unit comprises of several teams of engineers that coordinate their functions to provide three main inputs to the NLDC for the next day operation. These inputs are; generation unit commitment and schedule, list of planned transmission outages, list of precautions and control/operation strategies for network operations.

7.3.2.4 Control operation (NLDC) The National Load Dispatch Centre (NLDC) is nerve centre of the Peninsular Malaysia Grid. Team of Control Engineers and Technicians are manning the centre on a 24-hour basis to ensure that sufficient generation is scheduled to meet load demand and that the system will remain in secure situation following any disturbance. The NLDC communicates directly on real time basis to all power plants in the network and all major substations and load centres. Statuses, outputs and voltage levels of major equipment at power plants and substations are monitored closely and reporting system including alarms will alert operators in case of abnormal operating conditions.

7.3.3 Control of System Frequency In Malaysia, the electricity system operates at 50 Hz. This operational power frequency is kept very close to this level by all electricity users and generators. This is achieved by scheduling generation to match demand and by means of deliberate control actions on the part of some generators.

7.3.4 Control of System Voltage The control of voltage levels especially in distribution network is an important issue, due to its significance to the end users. The supply voltage needs to be kept within a given range for the correct operation of customer’s appliances. Although TNB tries to keep system voltages close to their nominal levels, the actual voltage varies as the load on the system changes. Voltages tend to fall when people are using a lot of electricity and they are often lower at the end of long distribution lines. The voltage at the customer’s terminal shall not vary from system terminal voltage of 6.6/11/22/33kV by more than ±5%, while for system


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voltage of 415/240V by more than +5% to –10%. Distribution networks are designed to provide electricity to users at reasonably constant voltage levels. Normally, voltage control in distribution system is provided by on-load tap changing transformer. The transformers that transfer power from the higher to the lower voltage system are fitted with automatic voltage control that compensate voltage changes on the high voltage side. In addition to this, switched and fixed capacitor banks are employed at strategic locations in the distribution system. Boosters are seldom used now because of their high costs. In the LV system, voltage regulators are employed but now being replaced by switched and fixed capacitors. The presence of distributed generation can assist in improved voltage profiles, but often makes the process of voltage control more complex. Conversely, power in-feeds from distributed generators tend to increase the voltage levels.

77..44 DDiissttrriibbuuttiioonn

7.4.1 Distribution Organisations TNB Distribution Division (known as TNBD), SESCo and SESB are the main distributors of electricity throughout the Peninsular, Sarawak and Sabah respectively. Until 2002, The Government has issued licenses to 26 companies who are allowed to operate as local distributors or suppliers of electricity in certain designated locations, such as shopping complexes and industrial parks. Some of these companies also operate their own co-generation plants to supply part of their demand.

7.4.2 Voltages In TNB distribution system, the network system voltage can be categorized into two: 1) Medium voltage (MV), which are 33kV, 22kV, 11kV, 6.6kV 2) Low voltage (LV) which are 415V and 240V In some areas in State of Perak and Johor, the 22kV networks are being converted to 33kV and 11kV. The sub-transmission feeding points into distribution systems are via HV/MV substations of 132/33 kV, 132/22kV and 132/11kV – normally called PMUs. MV network predominantly made up of underground cable while LV feeders are predominantly overhead lines with underground cable for selected commercial and housing areas.

7.4.3 Protection in Distribution Networks

7.4.3.1 Fault and fault current It is not possible to eliminate the electrical faults in distribution network due to it being exposed to environmental influence and the large geographical area that the network may cover. These faults may be caused by events such as overhead lines touched by trees, or the accidental excavation of underground cables. When these things happen, very high current can occur at the fault and in the parts of the network that feed current into the fault. If they are not quickly detected and stopped, these fault currents are a risk to life and can cause extensive damage to transformers, cables and other equipment, as well as affecting the electricity supply to customers.


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7.4.3.2 Protection system Circuit breakers and fuses are installed at strategic points in the network, together with protective relays and sensing devices such as current transformers. On detection of unusually high currents or other abnormal conditions by these sensing devices, the measured electricity basic quantities of voltage, current or frequency is then sent to relays, which are the decision makers. Depending on the magnitude of the measured quantity, the relay is set to do nothing or to trip the circuit breakers to interrupt the flow of current. These tripping devices and their respective functions are known as protection systems.

A properly coordinated protection system in distribution network is vital to ensure safety of public and to minimize the interruption to customers and the damage of equipment from the effect of faults. In typical utility practices, a protection system must satisfy the following requirements: Disconnection of equipment is restricted to the minimum necessary to isolate the fault. Sensitive enough to operate under minimum fault condition. Stable and remain inoperative under certain specified condition (such as through faults

and transients) Fast operation in order to clear the fault from the system to minimize damage to

affected system components. The typical types of distribution protection system are Over-current and Earth Fault (OCEF) and unit protection for feeders. OCEF relays are used to detect over-current and earth faults on underground cables and overhead lines, as well as transformers and capacitors. Pilot wire protections and directional over-current/earth fault relays are the two methods available for distribution feeders from 6.6kV up to 33kV.

The majority of faults occurring on overhead lines are transient faults due to lightning, swinging of wires, tree branch falling on the lines or because of animals. The advantage derived from auto reclosing is to reduce interruption time to the customers due to transient fault as well as to support fault isolation management. Auto reclosers and sectionalisers are installed on 33kV overhead lines system. These devices re-close the circuit breakers a few seconds after it is tripped. If the fault has not cleared by this stage, the protection will be activated and the circuit breaker will trip again. However, if the fault has cleared, the line will then remain reconnected to the supply.

Automatic re-closers are usually set to operate up to three or four times after a fault. If the fault does not clear after this number of operations, the circuit breaker remains tripped and must be re-set manually. The dead time between each successive reclosure is important information for DG in order that generator protections can be designed to avoid the auto-reclosure closing with the generator and the grid out of synchronism.

7.4.3.3 Fault level and equipment rating It is vital to have accurate information on fault level in the distribution system in order to decide the fault rating of equipment forming part of the network and to specify the parameters of the protection scheme. The system components must be rated such that during short circuit the resultant heat can be dissipated and mechanical forces will stood under maximum fault. The fault level must not exceed the short circuit rating of the circuit


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breaker interrupting the fault. The maximum fault level allowed in the distribution system are as follows:

Nominal System

Voltage (kV) Rated Voltage (kV) Fault Current (kA)

33 36 25 22 24 20 11 12 20

0.415 0.415 31.5 The equipment shall be rated to withstand the rated fault current for duration of 3seconds.

7.4.4 Distribution Network Planning Distribution network extension, modification and reinforcement are required to meet changing patterns of demand for electricity. Existing network infrastructure sometimes has to be upgraded to support growing demand for electricity. New housing developments, industrial sites and electricity generation schemes all require extension to distribution network. All of these changes have to be coordinated to maintain standard of safety, reliability and operation. Distribution Division of TNB has the responsibility to plan and develop their network, while maintaining the standards of safety and reliability, as well as maintaining system’s technical efficiency in line with the basic objective of distribution network planning to provide secure supply whilst fully meeting customer demand at the most economic overall cost, consistent with the nature of the load. Planning for the future in general begins with annual load forecasting followed by preparation of master plan, execution and evaluation of current system performance. The key sets of planning criteria involve security level standard, contingency criteria, loading criteria of network element under normal and emergency, fault level as well as equipment breaking duty.

7.4.5 Control and Operation of Distribution Network Variety of operational configuration in distribution network is useful to minimize disruption due to fault and routine maintenance. In the event of a fault, for example, the network operator can re-configure the network, selecting the configuration that maintains supplies to the greatest number of customers while the fault is being rectified. It is also being aided by the introduction of computer based, Distribution Automation System that enables the control and operation of distribution networks to be automated. The level of automation of the distribution system depends on the level of security of supply defined on certain areas or customers.

Distribution system operations are not entirely controlled and monitored via SCADA. Existing SCADA comprises of supervision and control at substation level and master station


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only while distribution feeder automation is under implementation stage. The number controlled and monitored distribution substation under the on-going SCADA program is only 10% of total number in the whole of TNB system by end of 2007. In addition, a program of wider placement of EFI and LFI is to be implemented in 2004 to improve operational flexibility and system efficiency in general. The EFI will be placed at incomer and outgoing feeder at every distribution substation and be later integrated with planned SCADA.


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88.. AAppppeennddiixx BB:: TTyyppeess ooff DDGGss 88..11 IInnttrroodduuccttiioonn

8.1.1 Energy Source Mechanical energy to turn the generator rotor is supplied by the prime mover. This involves energy conversion from mechanical energy to electrical energy. Some of the most common type of energy sources for DGs are: • Hydropower • Fuel Cells • Landfill Gas • Biomass • Wind Power • Geothermal • Photovoltaic If the installed capacity of DG Plants is taken into account by the utility in its energy and capacity planning, the reliability of the energy source must be considered. The availability of power from wind turbines is highly unpredictable. Landfill gas turbines, Geothermal and reciprocating engines are more reliable source of energy, with long outages to shutdowns for maintenance, which can be planned in advance. The reliability of hydropower turbines is also inherently very high but energy availability depends greatly on the pattern of water flow. For back pressure steam turbines, where the steam from the DG turbines is used for processes, the amount of generation is often dictated by the steam requirements of the plant at different times of the day.

The Government of Malaysia is signatory to the 1992 Rio Earth Summit and participated in the Berlin Summit. This requires the reduction of the greenhouse gases and thus renewable energy (RE) such as run of river hydro, solar, biomass and wind energy generation meets these objectives. Consequently any project using the RE sources should be given every assistance and prioroty to connect to TNB’s medium voltage (MV) network.

88..22 HHyyddrrooppoowweerr Hydropower is a valuable source of energy. Unlike other sources of energy, water retains its value even after it is used as a medium to generate electricity. Hydroelectric station uses water that is stored in a reservoir behind a dam or from run-of-river to drive the turbine. As the water rushes through the turbine, it spins the turbine shaft which produces mechanical power as shown in Figure 8.1. The mechanical power is then converted to electrical power through the generator, which is connected to the turbine.


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Figure 8.1: Pondage hydro-power scheme

There are generally three types of hydropower scheme namely: run-of-river; peaking or pumped storage; and impoundment.

Run-of-river uses natural flow of river without causing an appreciable change in river flow and the surrounding environment. Normally such system is built on small dam that impound little water. An example of this type of hydro is the Kenerong Hydro Scheme located in Ulu Kelantan A peaking or pumped storage station impounds and releases water when the energy is needed. In this method, excess energy is used to pump water from lower reservoir to an upper reservoir. During period of high electricity demand, the water is released to the lower reservoir to generate electricity. An impounded facility, typically a large hydropower station, uses dam to store river water in a reservoir – also termed as pondage hydro. This method allows water to be released constantly to generate electricity. Example of impounded facility is the Kenyir Hydro Station in Terengganu. The main advantage of hydropower is that it does not produce or emit any pollutant as by-product. In addition, its operating cost is very low and hydropower can respond quickly to utility load demand when it is required. On the other hand, high initial capital cost and potential environmental impact, especially for big hydropower plant are the main disadvantages. The


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environmental impact, however, can be avoided or reduced with proper planning in the initial stage of implementation.

88..33 FFuueell CCeellllss Fuel cells produced power electrochemically by passing a hydrogen-rich fuel over anode and air over a cathode and separated by an electrolyte. The by-products of the process are water, heat and carbon dioxide. Fuel cells was first discovered in 1839 by Sir William Grove who utilized four large cells, each containing hydrogen and oxygen to produce electricity which then used to split the water in the upper cell into hydrogen and oxygen. In 1959, the first practical application for fuel cell was developed, capable of powering welding machine. In the 1960s, NASA used fuel cell to power on-board electronics for space vehicles Gemini and Apollo. Fuel cell can be categorized into five different groups, distinguished by the types of electrodes used. The features of these fuel cells are summarised in Table 8.1. Fuel cell offers high efficiency and environmental advantage in comparison to some other technologies mainly due to the electrochemical process which does not require any moving parts. Phosphoric acid fuel cell can achieve up to 40 percent efficiency while molten carbonate and Solid oxide fuel cells have an efficiency of nearly 60 percent. In addition, fuel cells are virtually soundless, making it suitable to be used in premises where noise is a problem.

Table 8.1: Fuel Cell Characteristics

Type Operating Temperature Status and Application

Alkaline 50-100° C Mostly for space market, but is available for land vehicle.

Solid

Polymer

50-100° C Potential use for cars and buses.

Phosphoric

Acid

200° C Used for medium scale cogeneration application.

Molten

carbonate

600° C Used for medium and large scale cogeneration plant

Solid Oxide 500-1000° C Can be utilized for all sizes of cogeneration application.


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88..44 LLaannddffiillll GGaass Landfill gas occurs naturally wherever household and commercial waste is disposed off in engineered rubbish sites. As the organic matter in the buried waste decomposes it creates a methane-rich biogas. This is made up of about 55% methane and 45% carbon dioxide. It is the methane which is valuable as a source of energy for both heat and power. At a modern disposal site, excavated areas are progressively lined with an impervious material before being filled with waste and then capped over again. The lining and the capping help to prevent gas from escaping. Landfill gas is produced within about a year of the first tipping. It can continue to be exploited for up to decades afterwards. To utilize the biogases produced from the waste landfill, gas wells are drilled at few places on the disposal site as shown in Figure 8.2. The gas would first be filtered before being sent through gas collector line to drive the turbine that generates electricity.

Figure 8.2: Landfill generation

88..55 WWiinndd PPoowweerr Wind energy conversion systems are designed to convert the kinetic energy of wind movement into mechanical power, which is the movement of a machine. The mechanical power is then converted to electricity by the generator. The electricity generated can either be stored in batteries or used directly by connecting through utility distribution network. Wind turbine comprises of four basic components; the rotor, electrical generator, speed control system and the tower as depicted in Figure 8.3. Wind power fall into two broad categories:


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1) Horizontal axis with propeller type design 2) Vertical axis, Darrieus or ‘egg-beater’ design. The horizontal axis turbines are generally gear boxes and startup through the action without the need for an external motor vertical axis turbines are generally not equipped with gear boxes but are coupled directly to the most vertical axis turbines are not self starting. Both types of turbines normally employ induction generators which are well suited to the wide range of operating speeds possible.

Figure 8.3: Components of wind turbine

The startup time for a vertical axis turbine’ is less than one minute. Smaller machine started by connecting directly across the line larger machines reduced voltage starters may be employed to reduce inrush currents. System disturbances which cause such units to trip off line require a complete and restart of the machine. Wind power typically have no speed control or at best have relatively crude speed control such as varying blade pitch. It is therefore difficult to bring the slip speed of the induction generator to zero because closing the connecting switch to the utility system and voltage fluctuations are likely at the instant connection. The main factor affecting rate of load change is the inertia constant and its relation to wind speed changes. Despite being considered as environmental friendly, wind turbine has several disadvantages. Wind turbines are normally situated off shore and represent negative visual



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impacts. In addition, wind turbines produce acoustics noise and electrical interference which would be unpleasant to the surrounding environments.

88..66 MMiiccrroottuurrbbiinneess Microturbines are small combustion turbines with output ranging from 25kW to 1000kW. Microturbines evolved from automotives and trucks turbocharge auxiliary power units from airplanes and small jet engines used on pilotless military aircrafts. Most microturbines are typically single-shaft machines, with the compressor and turbine mounted on the same shaft as the electrical generator. It consists of only one rotating part, eliminating the need for gear-box and associated moving parts thus reducing maintenance and increasing reliability. Microturbine rotates at speed of 6,000 to 10,000 rpm driving either a two or four pole permanent magnet generator. The shaft is mounted on either oil lubricated bearings or air bearings. A key component of the microturbine is the recuperator, which transfers heat from exhaust gas to air that is sent to the combustor. Pre-heating combustion air reduces the fuel consumption and increases its overall efficiency to 25 to 30 percent. Further utilization can be gained by utilizing the waste heat from the turbine and incorporating heat recovery system to the unit.

Performance of microturbine is better as compared to bigger turbine where it’s combustion process is quieter and cleaner. Microturbines can achieve fuel to electricity efficiency up to 40 percent and produce less than 7 parts per million of NOX gas emission. Microturbines can burn a variety of fuels including natural gas, diesel, gasoline and methane. Microturbine provides an abundance of usable heat for hot water, absorption chilling, and distilling and direct heat applications. This supply of heat makes microturbine, when used in a combined heat and power application, highly efficient with its efficiency in the range of 70 to 80 percent. With maintenance cost forecast to be one third of the traditional reciprocating equipment and very high efficiency, microturbine is an attractive option.

88..77 GGeeootthheerrmmaall Geothermal energy is heat energy originating deep from the earth molten area. It is this heat which is responsible for volcanoes and earthquakes. The temperature in the earth’s interior is as high as 7000’C. There are four types of geothermal resources namely hydrothermal, geo-pressured, hot dry rock and magma. Of the four types, only the hydrothermal resource is currently commercially available. Hydrothermal resource comes in the form of either steam or hot water depending on the temperature and pressures involved. High grade resource is normally used for electricity generation and lower grade resource is used in direct heating applications. A typical geothermal plant is shown in Figure 8.4.


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Figure 8.4: Geothermal Power Plant


88..88 PPhhoottoovvoollttaaiicc Photovoltaic system uses semiconductors-based cells to directly convert sunlight to electricity. The semiconductor cells use thin film and crystalline silicon materials. The greater the intensity of the light, the more power it will generate. Photovoltaic system can be used to generate electricity at almost any scale, depending on how many modules are connected together. The cost of photovoltaic cell has been reduced by almost 50 percent since 1980 and the sales have been increasing steadily particularly in the remote power operation. PV cell was initially developed in the 1950s for use on satellites and space program and has been used widely as the source for satellites orbiting earth since 1960s. With technology advancement in the 1980s and 1990s, many applications of PV cell have been commercialized. The applications in use today include health care system, communications, security system, electricity supply and transport aids.

88..99 CCooggeenneerraattiioonn

8.9.1 Definitions of Cogeneration Cogeneration or more popularly known as combine heat and power (CHP) refers to the sequential generation of two different forms of useful energy (e.g. thermal and electrical) from the same amount of primary fuel input within a manufacturing process. This form of generation enhances the utilization of energy efficiently and is highly promoted by the Malaysian Government. Energy efficiency can be increased from 35% to 75 – 80% using


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this mode of generation. Figure 8.5(a) and 8.5(b) illustrate this approach of generation and its increased efficiency when compared to conventional generation.

Figure 8.5(a): Concept of Cogeneration – conventional generation Figure 8.5(b): Concept of Cogeneration – cogeneration



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8.9.2 Cogeneration plants in Malaysia Since 1993, Jabatan Bekalan Elektrik dan Gas (JBEG, now Energy Commission (EC)) had issued more than 26 licenses to major developers in the petrochemical, chemical, steel, refinery, pulp and paper, district cooling industries to generate electricity as part of their manufacturing processes. The list of developers and the amount of generating capacity for each project is shown in Table 8.2. The total generating capacity is 645.8 MW, which represents less than 6% of the maximum demand of Peninsular Malaysia. Most of this cogeneration plants uses either natural gas or process waste gas as the main source of fuel. Amongst these plants that are connected and operated in parallel to the distribution networks are summarized in Table 8.2.

Table 8.2: List of Co-generation plants in Malaysia

No Developer and plant address Fuel Installed Capacity

(MW)

Top Up/Export

(MW)

Standby (MW)

Inter-connection

Voltage (kV)

1

See Sen Chemical Bhd. Kawasan Perindustrian Telok Kalong, Kemaman, Terengganu

Process Waste Gas

6 - 2.4 11

2

TCL Industries (M) Sdn. Bhd. Kawasan Perindustrian Telok Kalong, Kemaman, Terengganu

Process Waste Gas

7 2.4 Export - 11

3 Gas District Cooling (M) Sdn. Bhd. Universiti Petronas, Tronoh

Natural Gas 8.4 - 0.5 11

4 Tractors Malaysia Sdn. Bhd. Kampong Puchong, Selangor

Natural Gas

1.2 0.9 - 11 (not parallel)

5 Gas District Cooling (M) Sdn. Bhd. Kuala Lumpur City Center

Natural Gas 26 20 Export - 33

6

Gas District Cooling (M) Sdn. Bhd. Kuala Lumpur International Airport

Natural Gas

60 - - 33

7 Gas District Cooling (M) Sdn. Bhd. Putrajaya Precinct 2

Natural Gas 10.8 - 0.5 33

8

Titan Petrochemicals (M) Sdn, Bhd. Tanjung Langsat Industrial Estate Pasir Gudang, Johor

Process Waste Gas

25 6 10 132

9 Shell Refining Company Bhd. Batu 1, Jalan pantai Port Dickson, Negeri Sembilan

Process Waste Gas

35 - 17.5 132


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The developments of cogeneration are essentially driven by the following key factors: Advancement in the technology for small-scale power generation e.g. efficient lesser

capacity generators. Energy efficiency or rational use of energy Deregulation or competition policy Environmental awareness – reduction in Green-House-Gas (GHG) emission.

Table 8.4 lists the various technologies used in Co-Generation or CHP plants.

Table 8.4: Cogeneration technologies

Main Prime Mover Average heat/power ratio

Back-pressure steam turbine 6.9:1 Pass-out condensing steam turbine 6.7:1 Gas Turbine 3.6:1 Combine Cycle 1.8:1 Reciprocating Engine 1.8:1


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8.9.3 Description of Cogeneration Technologies

8.9.3.1 Back-pressure steam turbine Back-pressure steam turbines exhaust steam at greater than atmospheric pressure either directly to an industrial process or to a heat exchanger. The higher the back pressure the more energy there is in the exhausted steam and so less electrical power is produced. The back-pressure steam turbines have an average heat to power ration of 7:1 and so, once the site electrical load has been met, any export of electrical power will be small. Figure 8.6 is a simplified diagram of a CHP scheme using a back-pressure steam turbine. All the steam passes through the turbine, which drives a synchronous generator, usually operating at 3000 rpm. After the turbine, the steam, at a pressure typically in the range 0.12 – 4 MPa and a temperature of between 200 and 300 °C depending on its use, is passed to industrial process or through a heat exchanger fou use in space heating.


Figure 8.6: Co-Generation scheme using a back pressure steam turbine


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8.9.3.2 Pass-out condensing steam turbine In a pass out (or extraction) condensing steam turbine (see Figure 8.7) some steam is extracted at an intermediate pressure for the supply of useful heat with the remainder being fully condensed. This arrangement allows a wide range of heat/power ratios.


Figure 8.7: Co-Generation scheme using a pass-out steam turbine

8.9.3.3 Gas Turbine Figure 8.8 shows how the waste heat of a gas turbine may be used. Gas turbines using either natural gas or distillate oil liquid fuel are available in ratings from less than 1 MW to more than 100 MW.


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Figure 8.8: Co-Generation scheme using a gas turbine with waste heat recovery


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99.. AAppppeennddiixx CC:: DDaattaa aavvaaiillaabbllee aanndd ttoo bbee ssuubbmmiitttteedd

9.1 Data Available from TNB at the Initial Stage A DG Developer upon recognizing the potential for connection of the DG plant to the local distribution network should make the necessary appointment to meet representatives of the local Distributor. At the initial meeting it will be useful for the DG Developer to brief the Distributor on the DG plant with the following basic information: 1) Location of plant 2) Type of generation and fuel 3) Capacity of plant Basic information that can immediately be obtained from the Distributor includes the followings: 1) Nearest substation, distribution lines or cables to the DG plant and their capacities; 2) The distance to the nearest connection point; 3) Three-phase short-circuit level at nearby substations; 4) Source transmission substation and loading profile (24-hour MW, MVAR for working

days and weekends) of the feeder where the plant would be connected; 5) Development of the network in the area; and 6) Any special problems that the Distributor faces with respect to power supply in the

area. It is important at this point for the Distributor to indicate to the DG Developer how the proposed DG plant should have its power output scheduled to ensure no spill-over of power to the transmission network (operation regime).


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9.2 Data to be Submitted by DG Developer for ‘Preliminary System Study’ – ES.08.01

After a preliminary assessment of a possible development of DG plant and contacts with the local Distributor, the Developer needs to know the cost estimate for connection to the local distribution network. The local Distributor in order to provide the cost estimates would need to carry out a ‘Preliminary System Study’ so that requirements for additional network components and reinforcements could be identified. For purpose of a preliminary system study, the Developer is required to submit a letter to local TNB offices. The letter should also describe basic parameters of the proposed DG plant.

Date: To: District/Regional Officer

Tenaga Nasional Berhad

Request for Cost Estimates of DG Connection DG Plant units & Capacity: 2 x 3MW Fuel Type: Hydro Location of Plant: Batu 4 Sg. Ping We refer to the above basic information on the proposed DG plant that we intend to connect to your distribution network. Enclosed herewith is the location map indicating the site of the DG plant and the nearest point to your distribution network facilities. We would be very glad to receive from you as soon as possible indications on the following items:

1) Cost estimates for connection; 2) Estimate of duration for implementation of connection; and 3) Operation regime of the DG plant.

Thank you. Yours Sincerely, (signed) DG Plant Developer



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9.3 Data to be Submitted for ‘Power System Study’ – ES.08.03

Based on the preliminary cost estimates of the DG plant implementation including connection costs, the Developer with the knowledge of possible operating regime of the plant would be in a good position to make assessment of the commercial viability of the project. In proceeding with the project, the DG Developer would enter the design stage where consultants would normally be appointed for the design and specifications of the plant. When details of the proposed plant are available, the DG Developer should now submit official application for connection to the local Distributor. The official application should be submitted in Form DG001 (see next page). This application form must be accompanied by details of the plant.


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FORM DG 001 APPLICATION FORM FOR CONNECTION OF DISTRIBUTED GENERATION/RE PLANT TO TNB DISTRIBUTION NETWORK

SECTION A: DEVELOPER INFORMATION Company

Address

Telephone Fax Email

Contact Information

Web site Telephone Handphone

Contact Person Name/Contact Information

Email SECTION B: FACILITY/PLANT INFORMATON Plant/Facility Address

Type of Plant (Hydro, Biomass, Landfilled Gas, Cogen) Telephone Handphone

Electrical Consultant Name & Contact Information

Email



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SECTION C: DETAIL EQUIPMENT INFORMATION Part 1 – General Information NO ITEMS DATA 1 Generator type 9 - synchronous

9 - asynchronous (induction type) 2 Rotor Construction 3 Generator rating (kVA) 4 Generator power factor 5 Rated terminal voltage (kV) 6 Frequency (Hz) 7 Rated speed (r.p.m) 8 Minimum power factor lagging 9 Minimum power factor leading 10 Type of prime mover 11 Generator voltage control 12 Generator Sub-Transient Reactance (p.u) 13 Generator Transient Reactance (p.u) 14 Excitation System Controls 15 Governor Controls 16 Leakage Reactance (p.u) 17 Inertia Constant (MW.sec/MVA) Part 2 - For Generator > 3 MW NO ITEMS DATA 1 Direct Axis Sub-Transient Reactance (p.u) 2 Direct Axis Transient Reactance (p.u) 3 Direct Axis Synchronous Reactance (p.u) 4 Quadrature-Axis Sub-Transient O/Cct Time Constant (p.u) 5 Quadrature- Axis Transient O/Cct Time Constant (p.u) 6 Quadrature- Axis Synchronous O/Cct Time Constant (p.u) 7 Direct Axis Sub-Transient O/Cct Time Constant (sec) 8 Direct Axis Transient O/Cct Time Constant (sec) 9 Direct Axis Transient O/Cct Time Constant (sec) 10 Quadrature Axis Sub-Transient O/Cct Time Constant (sec) 11 Quadratura Axis Transient O/Cct Time Constant (sec) 12 Zero Sequence Resistance (p.u) 13 Negative Sequence Resistance (p.u) 14 Zero Sequence Reactance (p.u) 15 Negative Sequence Reactance (p.u)


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Part 3 – Generator Transformer (if applicable) NO ITEMS DATA 1 Rated Capacity (MVA) 2 Voltage Ratio (HV/LV)

Max 3 Tap Range: Min

4 Vector Group (HV/LV) 5 Tap Step 6 Impedance (%) 7 Method of Earthing 8 Resistance Value (p.u) Part 4 – Short Circuit NO ITEMS DATA 1 Maximum 3-N Symmetrical S/Cct

Infeed into TNB Network (kA)

2 Maximum Zero Sequence Impedance of the User’s Network at the Point of Common Coupling with TNB’s Network (kA)

3 Breaker Rating (at point of interconnection) (1) Continuous (A) (2) Short-time rating (kA rated time) (3) Making Capacity (MVA) (4) Breaking Capacity (MVA/kA) Part 5 – Diagram/Plan to be Submitted NO Diagram/Plan (Tick (•) in relevant box) Tick 1 Site Plan 2 Single Line Diagram of any Existing or Proposed Arrangements of the

interface connection between TNB and Generator.

3 Generator Reactive Capability Chart 4 Protection System Data and Setting (Generator,Tx,CB,CT,PT) 5 Plant Single Line Diagram 6 Plant Load Profile 7 Open Circuit Saturation Characteristics 8 Block Diagram of Excitation System and Parameters


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1100.. AAppppeennddiixx DD:: TTNNBB DDiissttrriibbuuttiioonn PPllaannnniinngg CCrriitteerriiaa

1100..11 IInnttrroodduuccttiioonn This appendix outlines the planning/design criteria as applied by TNB to ensure that the distribution networks meet the following requirements: Secure electricity supply; Reliable electricity supply; High quality electricity supply; Optimal equipment utilization; Optimal network losses; and Safety of staff and public.

The purpose of the distribution system planning/design criteria is to provide the balance between the customer’s need for a safe, secure, reliability, high quality electricity supply and costs by TNB.

1100..22 DDiissttrriibbuuttiioonn NNeettwwoorrkk DDeessiiggnn PPhhiilloossoopphhyy TNB designs its distribution networks to operate as radial systems and under normal circumstances, the loss of a component of the network will result in the loss of supply to a number of customers connected to the sub-system. The duration of loss of supply is minimized through the use of fault indicators which improves fault location and hence isolation of the faulty sections. In certain designated supply load centres, SCADA is used to further minimize loss of supply duration. In urban, sub-urban and town areas, the distribution networks are configured an open meshed/ring network that is run radially with open points. By operating the network with open points, fault levels are reduced (as compared to closed rings or meshed) and simply technical and operational requirements. Open meshed/ring network arrangement allows improvements in supply restoration times following an outage. In rural areas where the total feeder maximum demand is less than 1MVA, the network operates in radial configuration without alternative supply.

The distribution system is not designed for islanded operation with distributed generation. DG must be designed to be disconnected from the distribution network if the feeder that the generator is connected to is separated from the remainder of the distribution system.

1100..33 NNeettwwoorrkk CCaappaacciittyy aanndd RReeiinnffoorrcceemmeenntt NNeeeeddss Network capacity and the need for network reinforcements are assessed by comparing the planning criteria with network planned performance level due to increase in load or addition of generation like DG Plant. To meet the planned performance levels in terms of security,


- 140 –


reliability and quality, the least cost option is normally chosen. The extent of network reinforcement works is dependent on the following:

Load forecast projections; The anticipated max demand of the customers or generation output; and Age and condition of the existing assets.

Economic analysis is applied in assessing network reinforcement requirements for the following purposes: To indicate returns of proposed capital investments; To choose the best options - least cost being the method used; and To minimise losses.

1100..44 DDiissttrriibbuuttiioonn SSyysstteemm PPllaannnniinngg//DDeessiiggnn CCrriitteerriiaa The planning/design criteria applied are a set of standards/requirements applied to ensure that the distribution network would be operated to the desired security, reliability and power quality. These criteria are used as planning and design limits/requirements to serve the interests of the customers connected to the network in terms of quality of supply and at minimum overall costs.

10.4.1 Steady State Criteria The steady state criteria define the adequacy of the network to supply the electricity/energy requirements of the customers within the component ratings, frequency and voltage limits. The steady state criteria apply to the normal continuous operating condition of the network and also include post supply interruption/post disturbance condition (or contingency condition) once the network has been normalized.

10.4.2 Steady State Voltage limits The distribution network must be designed to achieve a continuous network steady state voltages at the customer’s connection/interface during normal operating conditions are to be within the following limits: 1) ± 5 % at 33 kV 2) ± 5 % at 11 kV 3) + 5% and − 10% at .415 kV Under contingency operating conditions the steady state voltages are to be within the following limits: 1) ± 10 % at 33 kV 2) ± 10 % at 11 kV 3) ± 10% at 0.415 kV It must be emphasized that the steady-state voltage limits are measured at metering points or defined connection/interface and the voltage measured is phase to neutral.


- 141 –


10.4.3 Thermal Ratings Limits The thermal ratings of any network components must not be exceeded under normal or contingency conditions and those thermal limits are as follows:

1) Transformers: Specified by TNB / manufacturer name plate rating 2) Switchgears: Specified TNB / manufacturer name plate rating 3) Overhead Lines: Rating as specified by TNB 4) Underground Cables: Rating in accordance with IEC 60502-02 or as specified by

TNB 5) Overhead Cables: Rating as specified by TNB

10.4.4 Fault Level Ratings Limits (Short-circuit Rating) For safety reasons, the fault rating of any equipment must not be less than the fault level in the network at any time and for any normal network configuration. For system planning study purposes, the fault level calculated is not to exceed 90% of the fault rating of the existing equipment installed in the network. If fault level studies indicate that the calculated fault level is to be beyond 90% of the fault rating of the existing network beyond a certain specified year, provision has to be made by reconfiguring the network and steps be taken to have a higher fault rating for new equipment in the foreseeable future. The maximum fault levels permitted on TNB distribution network are currently as follows: 1) 11 kV – 20 kA 2) 22 kV – 20 kA 3) 33 kV - 25 kA Equipment owned and operated by TNB and connected to the network is designed to withstand these fault levels for 3 seconds (short time withstand current of 3 seconds).

10.4.5 Frequency Limits Under normal conditions, the transmission and distribution network frequency is maintained at 50 Hz ± 1%. Under emergency conditions that caused the frequency to drop below 49.5 Hz, under frequency load shedding scheme will operate to reduce load on the network so as to prevent total failure of the electricity system operated by TNB.

10.4.6 Security of Supply Criteria under Contingency Situation Security of supply under contingency relates to the ability of the network to be reconfigured after an outage of a network element and supply to the healthy portions of the network restored.

10.4.6.1 Network Reliability TNB will plan and design its networks so that the System Average Interruption Duration Index (SAIDI) is minimized.

10.4.6.2 Urban/Sub-Urban Medium Voltage Distribution Feeders Medium voltage distribution feeders in urban areas must be planned and designed so that, in the event of an outage of any network element, the load of the feeder can be transferred to adjacent feeders by manual or supervisory (when planned for) network reconfiguration.


- 142 –


The network shall be planned and designed so that in the event of a failure of a main intake sub-station transformer in the supply zone: all of the loads can be transferred to the other transformer in the main-intake sub-

station; or all the loads can be transferred to other main intake sub-station transformers within

the supply zone or other nearby adjacent supply zones. In essence, the deterministic criteria of single network element contingency i.e. (N-1) criterion is applied for medium voltage network planning for urban/sub-urban areas resulting in no loss of loss load during repair time.

10.4.6.3 Rural Medium Voltage Distribution Feeders (<1 MVA) For rural areas of total feeder load less than 1 MVA, the security of supply under contingency as in urban/sub-urban areas are not applicable. However, where economically feasible and reasonable, open point connections between feeders should be provided.

10.4.6.4 Low Voltage Distribution Networks Low voltage distribution service cables to users are planned as radial circuits. Where practical and safe, for urban areas, low voltage distribution networks are connected as open rings to provide an alternative supply in the event of circuit outages.

10.4.7 Power Quality Criteria Power quality criteria define the shape and limits on the deviations of supply voltage sinusoidal waveform in the distribution network. This is also referred to as the quality of voltage provided by TNB at the point of common coupling or interface with customers/generators. The following criteria have been established:

1) Power quality under steady-state conditions; 2) Power quality during transient disturbance conditions; 3) System frequency limits

10.4.7.1 Power quality under steady-state conditions Power quality under steady-state conditions refers to the quality of the normal voltage being supplied to the customer at the point of common coupling. It refers to voltage fluctuation or regulation, and limits for flickers, harmonics, as well as voltage unbalance.

10.4.7.2 Power quality during transient disturbance conditions Power quality under transient disturbance conditions refers to limits of variations of voltage quality during disturbances. The disturbances include outages, momentary interruptions, voltage sags and other transients.

10.4.7.3 System Frequency Limits of frequency must comply with the requirements of clause 10.4.5.


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10.4.7.4 TNB Power Quality Compatibility Limits The distribution networks as well as the transmission network are analyzed to ensure satisfactory performance, in accordance with TNB’s Power Quality Criteria, whenever a new customer is to be connected to TNB distribution network at the point of common coupling, or when a complaint is received from an existing customer. Harmonic Voltage, Voltage Unbalance and Flicker Limits will be analyzed depending on the nature of load of the new customer being connected to TNB. In summary, the compatibility limits currently being adopted TNB are summarized as in Table 10.1.

Table 10.1 - TNB Power Quality Compatibility Standards and Guidelines

Quality of supply

variation

Measurement Maximum permissible value for all sources

Standards/ Guidelines

Distortion Total Harmonic Distortion Voltage (THDV) %

5% at 415/240 Volts 4% at 11 and 22 kV 3% at 33 kV

Engineering Recommendation G5/4

Flicker Pst, Plt

Pst, 1.0, Plt 0.8 (at 132 kV and below) Pst, 0.8, Plt 0.6 (Above 132 kV)


Momentary Voltage Change Limits

V %

1 % - series voltage change that may lead to flickering problems 3%- single voltage change due to switching ON or OFF of any loads.


Voltage Unbalance

Negative Phase Sequence Voltage %

2 % for 1 minute duration Engineering Recommendation P24-1984 P29-1990

Voltage sag

% Remaining Voltage 50 % Sag (up to 200 ms) 70 % Sag (up to 500 ms) 80 % Sag (up to 1000 ms)

SEMI F47


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10.4.8 Conductor Selection Criteria TNB uses both underground cables and overhead lines in its distribution network. In designing extensions or network reinforcements, demand forecasts over a planning horizon is used to establish the network concept plan and the initial installations shall conform to the concept plans and TNB will use conductors that are appropriately sized.

To achieve cost efficiencies, standard overhead conductors and underground cable sizes have been designed.

System Planning, Engineering Services Engineering Services & Logistics Dept.

Distribution Division TNB

July 2004


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1111.. AAppppeennddiixx EE:: SSyysstteemm ssttuuddiieess aassssoocciiaatteedd wwiitthh tthhee ccoonnnneeccttiioonn ooff tthhee DDGG

1111..11 IInnttrroodduuccttiioonn Distribution networks are primarily designed to distribute power from central generation via transmission system to customer loads. In this configuration the power from the source i.e. central generation will flow through transmission system and distribution system and finally absorbed by customer loads. It is a straight forward one way power flow. But when distributed generation is introduced in distribution system the power flow becomes more complex and may flow both ways. In such a configuration the normal conventional way of planning, designing and operating the distribution system need to be reviewed. The present of local generation will alter the behaviour of the distribution system either at steady state or transient state. This will obviously affect the protection strategy and operation, the network design and operation and restoration operation after fault. Failure of either one of these will affect the safety of the operating personnel as well as the equipment. There are two stages of studies carried out by TNB for connection of a DG Plant to the distribution network: 1) Preliminary system study; and 2) Power system study.

The ‘preliminary system study’ has two main objectives: a) To determine the feasibility of connecting the DG Plant to the distribution network; and b) To determine estimation of cost for connecting the DG Plant to the distribution network. The ‘power system study’ is carried out after DG Developer has submitted formal application for connection and the study has the following main objectives: 1) To confirm the findings of the ‘preliminary system study’ 2) To determine additional control measures; and 3) To be used as guidelines for relevant technical specifications for the DG Plant. In this appendix methods and approaches to both preliminary and power system studies are elaborated to be as guidelines for TNB planning and design engineers.


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1111..22 PPrreelliimmiinnaarryy SSyysstteemm SSttuuddyy

11.2.1 Generating unit data When the DG Developer requests for feasibility and cost estimates of connections, the only information available to the distribution planning engineers are: 1) Number of generating units proposed and their capacities; 2) Quantum of power to be sent to the distribution network; 3) Fuel resource; and 4) Physical location of the plant including location map. Based on the fuel resource, the distribution planning engineer could use any of the following typical models available in the simulation software employed by TNB – PTI’s PSS/ADEPT (see figure 11.1): a) Steam turbine (small) – biomass units, cogeneration steam units b) Hydro without damper – mini hydro units c) Combustion turbine – gas turbine units

Figure 11.1: PSS/ADEPT generator model


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Tables 11.1 through 11.3 provide guidelines on typical data for synchronous machines that could be used for studies. Table 11.1: Typical data for HV synchronous machines

Salient pole generator with damper winding

Salient pole generator without damper winding

Type of Machine / Parameters

Turbo Generators

High Speed 2p < 16

Low Speed 2p > 16

High Speed 2p < 16

Low Speed2p > 16

Subtransient reactance (saturated) X”d (%)

9-32 14-32 15-25 22-35 25-40

Transient reactance (saturated) X”d (%)

14-45 20-32 22-36 22-35 25-40

Synchronous reactance (saturated) Xd (%)

120-300 80-140 75-125 80-140 75-125

No-load/Short-circuit Ratio

0.33-0.8 0.7-1.6 0.8-1.2 0.7-1.6 0.8-1.2

Negative sequence Reactance X2 (%)

9-32 14-25 15-27 36-63 36-60

Zero sequence Reactance X0 (%)

2 - 20 3 - 20 3 - 22 4 - 24 4 - 30

Subtransient time- Constant T”d (s)

0.02-0.05 0.02-0.05 0.02-0.05 - -

Transient time- Constant T’d (s)

0.4-1.8 0.7-2.5 0.7-2.5 0.7-2.5 0.7-2.5

Time constant of d.c. Component Tg (s)

0.07-1.0 0.1-0.4 0.1-0.4 0.15-0.5 0.2-0.5

Note: Generator resistance, Rg = 0.07X”d for Sng < 100MVA, Rg = 0.05X”d for Sng > 100MVA Table 11.2: Typical data for LV synchronous machines

Turbo Generator Pole Number

Salient pole generator

Pole Number

Rated apparent power (kVA) 40 - 1400 1600-3600

Subtransient reactance (saturated) X”d (%)

10 - 15 10 - 12 11 - 13

2 4

Transient reactance (saturated) Xd (%)

20 - 40 13 - 17 26 - 36

2 4

Synchronous reactance (saturated) Xd (%)

150 - 300 170 - 220 260 - 300

2 4

No-load/Short-circuit Ratio

0.4 - 0.8 0.6 - 0.7 0.4 - 0.5

2 4

Negative sequence Reactance X2 (%)

=X”d =X”d 2 - 4

Zero sequence Reactance X0 (%)

(0.4 - 0.8)X”d (0.4 - 0.8)X”d 2 – 4

Subtransient time- Constant T”d (s)

0.002 - 0.03 0.02 - 0.05 2 – 4

Transient time- Constant T’d (s)

0.006 - 1.0 0.5 - 1.2 2 – 4

Time constant of d.c. Component Tg (s)

0.008 - 0.1

4 - 14

0.03 - 0.15 2 – 4

Note: Generator resistance, Rg = 0.15X”d


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Table 11.3: Typical range of generator data Parameters Hydraulic Units Thermal Units

Direct-axis synchrounous reactance, Xd 0.6-1.5 1.0-2.3 Quadrature-axis synchrounous reactance Xq 0.4-1.0 1.0-2.3 Direct-axis transient reactance, X’d 0.2-0.5 0.15-0.8 Quadrature-axis transient reactance X’q - 0.3-1.0 Direct-axis subtransient reactance, X’’d 0.15-0.35 0.12-0.25 Quadrature-axis subtransient reactance X’’q 0.2-0.45 0.12-0.25 Direct-axis transient open circuit time-constant T’do 1.5-9.0 3.0-10.0 Quadrature-axis transient open circuit time-constant T’qo - 0.5-2.0 Direct-axis subtransient open circuit time-constant T’’do 0.01-0.05 0.02-0.05 Quadrature-axis subtransient open circuit time-constant T’’qo 0.01-0.09 0.02-0.05 Stator leakage inductance Xl 0.1-0.2 0.1-0.2 Stator resistance Ra 0.002-0.02 0.0015-0.005 Reactances are based on machine MVA in p.u. Time-constants in seconds

If only the d-axis parameters are known, the q-axis parameters can be estimated as:

1) Xq = 0.9 * Xd (0.65 * Xd for hydro) 2) X’q = 2.0 * X"d (can be 3 to 4 times higher)

In some cases, only the transient d-axis reactance X’d is known. In that case, the other reactances can be estimated using X’d. The relationships can also be used to fill in where one or two data items are missing. For Round Rotor Machines:

1) Xq = 5.33 X’d 2) Xd = 1.1 Xq 3) X’q = 0.3 Xq 4) X"d = 0.66 X’d 5) Xl = 0.66 X"d 6) T’do = 6.0 7) T"do= 0.035 8) T’qo = 0.6 9) T"qo= 0.07 10) s(1.0)= 0.13 11) s(1.2)= 0.4

For Salient Pole Machines: 1) Xq = 2.23 X’d 2) Xd = 1.57 Xq 3) X"d = 0.66 X’d 4) Xl = 0.66 X"d 5) T’do = 8.0 6) T"do = 0.05 7) T"qo = 0.1 8) s(1.0) = 0.11 9) s(1.2) = 0.5


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If only saturated values of the reactances are known, it is possible to estimate the unsaturated reactances needed for input stability simulations. The standard method for labeling reactances is:

1) Reactance at rated voltage (saturated) = X"dv 2) Reactance at rated current (unsaturated) = X"di

Similar terminology is used for the transient reactances. An estimate of the relationship between the two is:

1) X’di = 1.35 X’dv 2) X"di = 1.35 X"dv

The relationship varies significantly among machines; the range of the factor is about 1.1 to 1.45. There is usually little or no effect of saturation on the steady-state reactances and also no effect on X’q.

In all applications, the reactances must conform to the ratios:

a) Xd > X’d > X"d > Xl b) Xq >X’q > X"q > Xl

Note that subtransient saliency (i.e., where X"d • X"q) has negligible effect on transient stability calculation and is normally ignored. Thus, X"q is assumed equal to X"d.

11.2.2 Review/Update Network Model It is assumed that existing network model has already been established for all distribution networks in TNB. Before the DG Plant model is included in the network data, the existing data must be reviewed and updated to reflect the condition when the DG Plant will be connected. In particular the following updates must be included: 1) All new network additions – substations and circuits 2) Feeder loads must be updated in accordance to the latest load forecast In PSS/ADEPT network model, only the ‘Base Case’ load should be scaled. Load could be scaled by selecting all loads in the network or by categories of load. After the loads have been updated, at least 2 additional load snapshots should be prepared, namely: 1) Intermediate; and 2) Light load. Figure 11.2 illustrates an example of selecting load snapshots from a 24-hour load profile given in p.u. Since we require 3 load levels, the load levels from light to peak (0.4 to 1.0 respectively) are divided into three equal sections – in the case of figure E.2, having four pints at 0.4, 0.6, 0.8 and 1.0. Peak load level should be chosen as 1.0 p.u. and light load level 0.4 p.u. However, for intermediate load the load level should chosen at the middle of intermediate load duration, about 0.7. The duration of each load levels are then determined from the intersections of the four load level points with the load duration curve. These values are to be for defining the load snapshots of network model in PSS/ADEPT.


- 150 –

0

0.2

0.4

0.6

0.8

1

1.2

1 6 11 16 21

Time (hours)

Load

(p.u

.)

LoadDuration

Base/Peak Intermediate Light

Intermediate Load Level

Load

Load duration

Peak Load

Light Load

Figure 11.2: An example of calculating load snapshots

After the network model without the DG Plant has been established and checked, the DG Plant could then be included in the model.

11.2.3 Connecting DG Plant and Modelling Approach Generally there are four possible ways of connecting a DG Plant to the distribution network: i) Isolated with no grid connection – operate independently of the distribution

network; ii) Isolated with automatic/manual transfer – under normal condition operates

independently from distribution network and automatically/manually connected to the distribution network on loss of DG Plant generation sources;

iii) Connected to the distribution network and operates parallel without export of power;

iv) Connected to the distribution network and operates parallel with import/export (bi-directional power flow) possibilities.

Case (i) is the least complex and case (iv) is the most in term of system studies, planning and design. Before a DG Plant is connected to a network bus, the voltage level at that bus must be within the criteria range (see Appendix D). A planning/design approach that ignores the reactive power contribution (sending and absorbing) of the DG Plant is normally used. This approach ensures that the voltage in the distribution network would be maintained within criteria limit on loss of the DG Plant. If there is one generating unit, it can be set as



- 151 –

‘constant power’ unit with zero reactive power output (power factor 1.0) as illustrated in figure 11.3. Figure 11.3: Constant power unit on power factor = 1.0 If there are several generating units in the DG Plant with its own loads, the generators must also be set to constant power factor with reactive power output to match the DG Plant loads. The objective is to have negligible reactive power flow through the interface. Normally, there may be more than one option of connecting the DG Plant to the network. Where the DG Plant has its own distribution network, the network together with generating units and interface transformer(s) must be modelled.



- 152 –


The interface transformer has major influence on the short-circuit contribution of the DG Plant to the distribution network and therefore its parameters particular positive and zero sequence impedances must be reasonably modelled. Table 11.4 shows minimum impedance values for different size transformers in accordance with the requirements of IEC 76. In PSS/ADEPT, the zero sequence impedance of the transformer would be assumed to be the same with the positive sequence. What will influence the zero sequence current contribution is the grounding of the star point of the interface transformer. The minimum impedance value should be used in the ‘preliminary system study’ for maximum contribution of fault current from the DG Plant. Table 11.4: Minimum transformer impedance (IEC 76)

No kVA Range Minimum +Ve sequence impedance (%)

1 Up to 630 4 2 631 – 1,250 5 3 1,251 – 3,150 6.25 4 3,151 – 6,300 7.15 5 6,301 – 12,500 8.35 6 12501 – 25,000 10 7 25,001 – 200,000 12.5

11.2.4 Network Voltage Profile Clearly, with DG connected to the distribution network the voltage profiles will be altered. The load flow analysis could be used to determine the voltage profiles in the network particularly the feeder where DG is connected. The analysis should be carried out under at least the three load conditions of peak (base), intermediate and light. For voltage profile analysis, the generating unit must be set to power factor of 1.0. With DG connected to the distribution network, it must not cause the network voltages to stray outside any statutory limits and the limits defined by the planning criteria. As the power is forced through the feeder towards the source, the voltage will rise in the direction of the generator terminals. Since distribution transformer uses fixed tap, such voltage rise will reflect directly through to LV customers. This aspect will tend to be the significant limiting factor in dictating the maximum size of generator that can be accommodated at a specific voltage level.

Clearly, the potential for greatest voltage rise will occur when the distribution network is during light load since this condition hinders the local absorption of the exported power. The degree of voltage rise will be related to:

1) Type of generator and its associated control systems – assume power factor of 1.0; 2) The location of the DG Plant in the feeder; 3) The level of export relative to the minimum load condition; 4) The distribution of load on the feeder; and 5) The size of the feeder conductors and its connections to the DG Plant.

To illustrate voltage profile analysis a distribution network as shown in figure 11.4 is modeled in PSS/ADEPT. An existing 11kV feeder with uniformly distributed load is where the DG Plant is to be connected. To illustrate the effects on voltage profile, the DG will also


- 153 –

be connected to the middle and beginning of the feeder. Effects of additional 11kV feeder and distribution at higher voltage level of 33kV would also be demonstrated.

Feeder with uniformly distributed load

DG Plant

33kV

11kV

33kV33kV connectionalternative

Additional 11kV Feeder

Figure 11.4: Example uniformly distributed load feeder for voltage profile analysis

11.2.4.1 Voltage Profile Without the DG Without the DG Plant, the voltage profile along the feeder is shown in figure 11.5. In this example, the voltage at the end of the feeder is slightly below the criteria limit of 0.95 p.u. during peak load.

0.9

0.95

1

1.05

1.1

0 5 10 15 20 25 30 35 40 45 50

Distance (km)

Vol

tage

(p.u

.)


Figure 11.5: Feeder voltage profile without DG Plant



- 154 –

11.2.4.2 Voltage Profile DG at the end of feeder The voltage profiles with the DG located at the end of the feeder with generator export of 500kW and 1000kW are shown in figures 11.6 and 11.7 respectively. With 500kW output voltages remain within criteria for all nodes throughout the load levels – peak, intermediate and light. It must be noted that the DG contributes to significantly to increase and flatten the voltage profile along the feeder. When the power export to distribution network is increased to 1000kW, voltage profile along the feeder is raised to significant level beyond the criteria limits particularly during light load.

0.9

0.95

1

1.05

1.1

0 5 10 15 20 25 30 35 40 45 50

Distance (km)

Vol

tage

(p.u

.)


Figure 11.6: Voltage profile, DG at end of feeder, 500kW export

0.9

0.95

1

1.05

1.1

0 5 10 15 20 25 30 35 40 45 50

Distance (km)

Vol

tage

(p.u

.)


Figure 11.7: Voltage profile, DG at end of feeder, 1000kW export

When a DG is connected at the end of a feeder, voltage profile analysis would indicate the limit on power export to the distribution network and thus the total size or capacity of the DG Plant units.

Since the approach is for the DG Plant not to contribute reactive power regulation (constant power factor at 1.0), a sudden loss of the unit would not result in voltage limit violation.



- 155 –

11.2.4.3 Voltage Profile DG at the mid of feeder Figures 11.8 through 11.10 show voltage profiles at the three load levels for various DG Plant power export when it is located in the mid of the feeder. An export of 1000kW would result in voltage to be slightly out of the criteria range near the generator bus.

0.9

0.95

1

1.05

1.1

0 10 20 30 40 50

Distance (km)

Vol

tage

(p.u

.)PeakIntermediateLight

Figure 11.8: Voltage profile, DG at mid of feeder, 500kW export

0.9

0.95

1

1.05

1.1

0 10 20 30 40 50

Distance (km)

Vol

tage

(p.u

.)



0.9

0.95

1

1.05

1.1

0 10 20 30 40 50

Distance (km)

Vol

tage

(p.u

.)



When located at the mid of the feeder, amount of export could be increased but voltage remains the limiting factor.



- 156 –

11.2.4.4 Voltage Profile DG at the source of feeder When the DG Plant is located near the source of the feeder, the amount of export to the distribution network could be increase further with respect to voltage limits as indicated in figure 11.11 through 11.13. In this case a maximum export of 2000kW would result in voltage to slightly outside the criteria range (see figure 11.12).

0.9

0.95

1

1.05

1.1

0 5 10 15 20 25 30 35 40 45 50

Distance (km)

Vol

tage

(p.u

.)


Figure 11.11: Voltage profile, DG at the source of feeder, 500kW export

0.9

0.95

1

1.05

1.1

0 10 20 30 40 50

Distance (km)

Volta

ge (p

.u.)



0.9

0.95

1

1.05

1.1

0 10 20 30 40 50

Distance (km)

Volta

ge (p

.u.)





- 157 –

11.2.4.5 Voltage Profile DG at end of feeder with additional 11kV feeder As an example, we investigate the impact on voltage profile of a reinforcement comprising of an additional 11kV circuit operating in parallel with the existing feeder as shown in figure 11.14.


11kV ParallelFeeder

Figure 11.14: Reinforcement with parallel 11kV feeder We examine the impacts of voltage profile with the additional 11kV parallel feeder. Without any DG output, the cable capacitance results in slight increase in voltage at the end of the feeder as shown in figure 11.15.

0.9

0.95

1

1.05

1.1

0 5 10 15 20 25 30 35 40 45 50

Distance (km)

Vol

tage

(p.u

.)


Figure 11.15: Voltage profile, with parallel 11kV feeder DG output = 0.0 kW


- 158 –

The addition of the long 11kV feeder cause voltage rise to appear at lower DG output as compared with the one without the additional feeder (see figure 11.16).

0.9

0.95

1

1.05

1.1

0 5 10 15 20 25 30 35 40 45 50

Distance (km)

Vol

tage

(p.u

.)


Figure 11.16: Voltage rise at 500kW output with parallel 11kV feeder The above result shows that a feeder reinforcing the network may not serve to eliminated or reduce the voltage rise problem. Therefore, voltage profile must again be examined when reinforcement particularly using long circuits is attempted.

11.2.4.6 Voltage Profile DG at end of feeder with 33kV feeder connection Another possible reinforcement is to have circuit at the next voltage level as shown in figure 11.17 using 33kV line. In this example, DG output is transferred using the 33kV circuit.

33kV Feeder

Figure 11.17: Use of 33kV feeder for power transfer



- 159 –

The 33kV circuit significantly improves voltage profile performance even with high DG kW export as indicated in figures 11.18 through 11.20.

0.9

0.95

1

1.05

1.1

0 10 20 30 40 50

Distance (km)

Vol

tage

(p.u

.)


Figure 11.18: 33kV feeder, 500kW export

0.9

0.95

1

1.05

1.1

0 10 20 30 40 50

Distance (km)

Volta

ge (p

.u.)



0.9

0.95

1

1.05

1.1

0 10 20 30 40 50

Distance (km)

Vol

tage

(p.u

.)



In the example of using 33kV feeder, the limiting factor is overload of circuits.



- 160 –

11.2.5 System Losses Losses must be treated as an important attribute of the DG Plant. Therefore, in planning the main principle to be followed is that ‘the connection of the DG must not result in increase in system losses’. It must never be assumed that a DG Plant connection will contribute to reduce losses. The following results using network of figure 11.4 indicate the behaviour of system losses.

11.2.5.1 Losses DG at the end of the feeder Figure 11.21 shows losses and voltage profiles with different DG kW outputs. If loss at peak without DG is used as the limit, the DG output with respect to loss limit can be as high as 3000kW. However, the limiting criterion is the voltage where the maximum export at peak is limited to less than 1500kW. If the output is limited to the voltage limit of 1.05 (maximum of about 1300kW), this corresponds to minimum (reduced) loss for the feeder.

0

50

100

150

200

250

300

350

400

450

500

0 1000 2000 3000 4000

DG Output (kW)

Feed

er L

osse

s (k

W)


0.9

0.95

1

1.05

1.1

1.15

1.2

0 1000 2000 3000 4000

DG Output (kW)

Volta

ge (p

.u.)


Loss limit(use peak)

Voltage limitRange

Figure 11.21: Loss variation with DG connected at the end of the feeder When a DG is connected to the end of the feeder, voltage limit may be the limiting factor for export as compared to loss limit.



- 161 –

11.2.5.2 Losses DG at the mid of the feeder When the DG is located at the middle of the feeder, losses are reduced significantly with DG Plant maximum export of slightly less than 5000kW (see figure 11.22). However, voltage criterion requirement results in limiting the DG Plant output to less than 2500kW


0

50

100

150

200

250

300

350

400

450

500

0 1000 2000 3000 4000 5000

DG Output (kW)

Feed

er L

osse

s (k

W)


0.9

0.95

1

1.05

1.1

1.15

1.2

0 1000 2000 3000 4000 5000

DG Output (kW)

Volta

ge (p

.u.)



Voltage limitRange

Figure 11.22: Loss variation with DG connected at the mid of the feeder When a DG is connected to the mid of the feeder, voltage limit may also be the limiting factor for export as compared to loss limit.


- 162 –

11.2.5.3 Losses DG at the source of the feeder When the DG is located at the source of the feeder, the amount of export could increased significant from both the perspective of losses and voltage (see figure 11.23). However, voltage criterion requirement results in limiting the DG Plant output to less than 3500kW

0

50

100

150

200

250

300

350

400

450

500

0 1000 2000 3000 4000 5000 6000

DG Output (kW)

Feed

er L

osse

s (k

W)


0.9

0.95

1

1.05

1.1

1.15

1.2

0 1000 2000 3000 4000 5000 6000

DG Output (kW)

Volta

ge (p

.u.)



Voltage limitRange

Figure 11.23: Loss variation with DG connected at the source of the feeder

Based on the above analysis, the output (the quantum of export) of the DG when connected to existing feeder would significantly limited by voltage limit criteria.



- 163 –

11.2.6 Short-Circuit Analysis The connection of DG will contribute to the local system fault level. All of the associated switchgears must be able to withstand the stress to which they are subjected. Fault level study has to be carried out and it shall not exceed 90% of the rating of the associated switchgears or TNB design fault level. Network protection will cause a delay in tripping, as a result fault breaking will be a less onerous condition since fault current have been reduced. Detail knowledge on the protection operating time and the time constant of a particular generator are required to assess this situation. Therefore, particular attention must be paid to: 1) Increase in 3-phase fault MVA (90% limit) 2) Making capacity For calculating of making duty, a multiplying factor of 1.8 should be used on the 3-phase fault MVA level. To illustrate the analysis of DG Plant contribution to fault level, a network in figure 11.24 is used.


25kA, 3-phase

Tx with NER

Tx with NER150A, min.IEC imped.

Tx with minIEC impedance

Figure 11.24: Network for fault level analysis The following modelling assumptions are to be used:

1) Source must be modelled with maximum value of fault kA – for 33kV, 25kA for 3-phase is used;

2) Step-down transformer (at Main Intake S/S) impedance must be based on the actual. If however, the values not available, minimum IEC impedance should be used;

3) Step-down transformer (at Main Intake S/S) NER must be modelled; 4) DG interface transformer minimum IEC impedance should be used; and


- 164 –

5) DG interface transformer NER must be modelled for 150A contribution the distribution network.

When evaluating the impact of DG Plant on fault level, it is important to look at the 415V busbar after the LV step-down transformer. This is because the fault rating of 31.5kA for LV equipment may be exceeded with increase fault level due to DG Plant contribution. For fault level evaluation the LV transformer tap should be set to the maximum, that is, with highest possible voltage. The fault current contribution of the DG Plant is most critical when it is located near the source bus as illustrated in figure 11.25. In this example, the LV bus has exceeded the 90% limit. The making duty of the 415V and 11kV breakers are 51.6kA and 28.0kA respectively and these should be checked against the actual make rating.

91.1%

77.9%

51.6kA

28.0kA

Figure 11.25: 3-phase fault level assessment



- 165 –

11.2.7 System/Feeder Adequacy Based on previous analysis, feeder capacity is not normally the limiting parameter in terms of DG Plant output to the distribution network. As an example, feeder overload occurs when the DG output is 4MW (see figure 11.26). However, at this power export overvoltage of 1.22 p.u. has already occurred.

Overload

4MWOutput

Figure 11.26: Feeder overload is not limiting export when DG Plant at the end of the feeder. If the DG Plant is located in the middle of the feeder, overload would occur at higher MW output. In this case 5.5MW as shown in figure 11.27. However, as in the previous case, the limiting factor remains voltage and not circuit capacity. When the DG is located closed to the source, overload/circuit capacity and voltage issue are limiting DG output as indicated in figure 11.28.



- 166 –

Overload

5.5MWOutput

Figure 11.27: Feeder overload is not limiting export when DG Plant at the end of the feeder.

6MWOutput

Figure 11.28: Feeder overload and voltage are not limiting export when DG Plant at the source.



- 167 –


1111..33 PPoowweerr SSyysstteemm SSttuuddyy Power system study is carried following formal submission of application for connection of the DG Plant to the distribution network and confirmation of all input data and parameters. As stated earlier the main objectives of the ‘power system study’ are: 1) To review the results/findings of the ‘preliminary system study’ with revised input data; 2) To examine additional control requirements to mitigate possible problems; and 3) To establish functional specifications of the interface and associated equipment for use

by the DG Developer. Apart from reviewing the ‘preliminary system study’, the ‘power system study’ has to include two new studies: 1) Stability; and 2) Insulation coordination.

11.3.1 Stability Analysis Study on local distribution network stability and security need to carried out for every DG installation especially for DG with a capacity of more than 5 MW. For DG installation that is less than 1 MW the study might be waived. In this study the frequency and the voltage stability need to be confirmed under fault condition. Frequency stability is analysed by tracking the frequency at each substation as it evolves over time. If the frequency values either remain constant (at the nominal value of 50Hz) or converge to a different equilibrium value then the system is stable. On the other hand if a small disturbance at one substation in the system causes the frequency at one or more substations do diverge from equilibrium then the system is said to be unstable. The scenarios for this study are both at peak load and base load conditions with disturbance introduce at various selected critical points in the network. It is important also to study the stability and the security of the network that has been detached (if any) from the grid due to loss of mains -islanded network. This would determine how DG should react under such a condition.

11.3.1.1 Models for Excitation Control If model and parameters for excitation controllers are not provided, typical models as found in PSS/E and PSS/VIPER manuals could be used.

11.3.1.2 Models for Speed-Governor If model and parameters for speed-governor controls are not provided, typical models as found in PSS/E and PSS/VIPER manuals could be used.

11.3.1.3 PSS/ADEPT Network Model to PSS/E Dynamics TNB currently employs PSS/ADEPT for distribution network analysis. This tool will be used in most of the analysis required in the ‘preliminary system study’ and the first part of


- 168 –

‘power system study’. TNB also uses PSS/VIPER for dynamic analysis. This way requires that PSS/ADEPT network model for steady-state analysis be reentered into PSS/VIPER. However, a new approach is being developed that the PSS/ADEPT network model can be translated for use with PSS/E for dynamic simulations. As an example, a distribution network in figure 11.29 is to be examined in terms of transient stability. Figure 11.29: Sample network for stability analysis in PSS/ADEPT

In PSS/ADEPT, the network data can be saved into a HUB format and this format could read in PSS/ADEPT Utility as shown in figure 11.30. PSS/ADEPT Utility is a program that converts PSS/ADEPT file to PSS/E and thus ready for stability simulations.



- 169 –

Figure 11.30: Reading PSS/ADEPT HUB File into PSS/ADEPT Utility Currently the Utility converts PSS/ADEPT generator data to corresponding PSS/E dynamic data but without excitation and speed-governor controls. The two controls will have to be added separately to the dynamic data file. In PSS/ADEPT Utility, stability simulation with PSS/E in the background can be carried out as shown in figure 11.31 and 11.32.



- 170 –

Figure 11.31: Stability simulation setup

Figure 11.32: Stability run



- 171 –

Figure 11.33: Specifying disturbance

11.3.1.4 Stability Analysis Analysis of stability simulations is based examination of the system responses to disturbances. As an example, rotor angle response as shown in figure 11.34 would indicate whether or not out of synchronism had occurred. Figure 11.34: Response of states and controls following system disturbances



- 172 –


11.3.2 Insulation Coordination Analysis Insulation coordination study is particularly important when overhead lines are involved. The objective of the study is to examine possible overvoltage conditions following contingencies and to ensure that sufficient insulation and protection are provided. Insulation coordination study is not yet carried out by TNB. In this guidebook, insulation coordination study has been proposed to be carried out and therefore TNB is encourage to explore further.


- 173 –


1122.. AAppppeennddiixx FF:: PPrrootteeccttiioonn aanndd CCoonnttrrooll RReeqquuiirreemmeennttss

1122..11 IInnttrroodduuccttiioonn The protective requirement must be based on the need to detect system faults and malfunctions both within the DG installation as well as the TNB distribution feeder. On detection of fault or malfunction, the relays must trip appropriate circuit breakers to isolate the faulty section to minimize equipment damage and safety hazards during the faults whilst maintaining power supply continuity on healthy parts of the system.

Although the design and types of protection for the DG installation including its generating units is the responsibility of the DG Developer, TNB must ensure that these protections are properly coordinated for reliable and safe operation of the distribution feeder to protect TNB equipment and safety of other TNB customers. The basic philosophies for the types and design of the protection schemes are that: a) For any internal fault within the DG installation, the DG must not cause problems to the

utility system and the customers. b) For any distribution fault, the generator must be protected from any damaging effects.

1122..22 TTyyppeess ooff PPrrootteeccttiioonn RReeqquuiirreemmeennttss The following paragraphs describe the various functions of the required protections under various types of faults and conditions.

Under voltage (UV) and Under Frequency (UF) relays are designed to trip the generator when the distribution feeder is taken off. When the feeder is supplying load greater than the capacity of the generator, under frequency and under voltage are expected to occur and UV and UF relays will operate to trip the generator (see figure 12.1). The setting of the under frequency trip (Hz) must be based on the recommendation of the manufacturer.


- 174 –

DG

S

Main Intake

DG Plant

Feeder 1

Feeder 2

Feeder 4

Feeder 5


Figure 11.1: Illustration of UV and UF relays operation

When the feeder load is sufficient to be supplied from the generator under islanded operation, UV and UF relays may not operate. Therefore, under the current operational practice, this condition where flow to the feeder at the source will result in sustained islanded operation of the DG Plant with feeder must be avoided by rescheduling the DG export to the distribution network. If the resulting feeder load could be totally supplied by the generator under islanded operation, this may present a hazard to personnel. Generator damage would be likely when the feeder breaker is reclosed. In distribution systems, feeder breakers are not equipped with dead line check to prevent reclosing on live feeder. An alternative to dead line check relays is an automatic transfer trip that upon opening of the utility feeder breaker, a signal is provided to trip the generator. Any islanded operation required later must be performed based on operation and safety procedures agreed by both the generator and the utility. If the feeder load to be supplied by the generator is less than the generation, over-frequency will occur and therefore OF relay is required as illustrated in figure 12.2. The setting of the OF relay must also be based on the recommendation of the generator manufacturer.

BR3

BR1

BR2

BR4

BR5

2MW 3MW

Total load5MW

UFUV

1. BR3 open2. DG to supply 5MW with 3MW turbine power limit then:

• Underfrequency trip; or/and• Undervoltage trip.


- 175 –


DG

S

Main Intake

DG Plant

Feeder 1

Feeder 2

Feeder 4

Feeder 5

Figure 12.2: Illustration of OF relay operation OV relays are installed on the DG side to protect against over-voltage resulting from a sudden loss of load. However, the generator voltage regulator will take care of the over-voltage by reducing excitation. Therefore, the over-voltage relay would be useful when the voltage regulator is defective or limited that it would result in sustained over-voltage. Transient over-voltages due to switching or lightning should be catered for by the design of the distribution and DG systems insulation.

To prevent damage on the prime mover due to motoring of the generator during reversal of power, RP or directional relays are installed. Time delay must be incorporated to prevent nuisance tripping during synchronization of the generator.

Combined over current and earthfault (OCEF) relays are employed for protection of over-current and earthfault in both directions. IDMT relays equipped with instantaneous trip are used in this case. For large generators provided with its own unit protection, the OCEF relays are used as backup for the generator internal fault. On distribution system fault, both generator OCEF and feeder OCEF would see these fault currents. Coordination of the generator OCEF relays with that of feeders would become more difficult due flow of fault currents from both sources into fault. It is normal practice that on a distribution fault on the feeder, the feeder OCEF is allowed to trip first followed by the generator. If the fault is cleared and the generator operates in isolation then frequency and voltage relays would likely to operate depending on the generation-demand balance. However, if inter-trip is provided, the generator would also be tripped out.

Loss of synchronism manifested into generator over-speed or under-speed that would be detected by the generator mechanical speed relays.

BR3

BR1

BR2

BR4

BR5

2MW 3MW

Total load1MW

OF

1. BR3 open2. DG to supply only 1MW with 3MW turbine power:

• Overfrequency trip.


- 176 –


Field failure (FF) relays is employed to detect malfunction of the generator excitation field. Upon loss of excitation, the generator rotor accelerates to above synchronous speed where it continues to generate power as an induction generator. Loss of field is normally detected by an undercurrent relay connected to a shunt in the field circuit.

Negative phase sequence relays are employed to detect excessive unbalanced loading of the generator.

To summarise, the requirements of protection are as follows: i) Undervoltage (UV) ii) Over-voltage (OV) iii) Under Frequency (UF) iv) Reverse Power (RP) v) Over-current (OC) vi) Earthfault (EF) vii) Step-up transformer differential protection - above 5MVA requires unit protection

(TD) viii) Loss of system synchronization/Field failure relay (FF)


- 177 –


1122..33 DDiissttrriibbuutteedd GGeenneerraattoorr PPrrootteeccttiioonn SScchheemmee Figure 12.3 shows the functional details of the required DG protection scheme. All the relaying code used follows the TNB protective device code.

Figure 12.3: Distributed Generator protection schemes


- 178 –


1122..44 SSuummmmaarryy ooff TTNNBB’’ss DDiissttrriibbuuttiioonn PPrrootteeccttiioonn PPrraaccttiicceess “The Protection and Control: Code of Practice (2nd Edition)” was launched in May 2003 as a main guidebook to standardize the policies, schemes and practices on the protection, control and their supporting equipment for all TNB core business, Generation, Transmission and Distribution Divisions. All TNB primary equipment shall be protected against damages from any type of faults. For all external parties such as IPPs, co-generators and bulk customers, their primary equipment shall also be protected against damage from any type of faults and shall follow the setup and schemes specified as in the guidebook.

12.4.1 General Requirement

12.4.1.1 Maximum Fault Clearing Time, Operating and Reset Time The maximum fault clearing time is defined as the maximum time interval between the fault inception and the fault clearance of the faulty element from the power system.

For substation and transformer faults, the fault clearing time must not exceed 150ms, while for cable and overhead lines the maximum fault clearing time allowed is 600ms. These requirements applied for 33kV, 22kV and 11kV systems for the Main protection relaying scheme,

For the Backup protection relaying scheme, the maximum fault clearing time shall not exceed the short-circuit rating of the primary equipment.

Maximum Pickup time, maximum operating time and maximum reset time shall be standardized not to exceed 50ms.

1122..44..11..22 PPrrootteeccttiioonn RReellaayyss The general requirements for protection relays to be used in TNB system are as follows: 1) Relays shall be suitable for operation on D.C system in the range of 80% to 120% of

the nominal 110V DC or 30 V D.C without the use of voltage dropping devices. The condition also applies for D.C/D.C converter.

2) All protective relays shall be stable and not be affected by a slow decay, surges, dips, ripples, spikes and chattering of the D.C supply.

3) The protective relays shall not give a trip output signal when D.C supply is lost and during restoration.

4) The Relays shall be housed in dust and moisture proof cases according to IEC 60529 and shall be suitable for duty under tropical climate.

5) The relays shall be insensitive to the capacitive effect of control cable. 6) All relays shall be correctly rated to the current transformer secondary rating and

voltage transformer secondary rating. 7) Reset facilities shall be made available, either electrically or mechanically and all

indicators shall be clearly visible without opening of relay front cover or relay panel door.


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8) The relays contacts shall be suitably rated for tripping, control and indication purposes and sufficient number of contacts shall be provided separately for tripping, control and alarm functions.

9) The relays, whether mounted in panels or not, shall b provided with clearly inscribed labels describing their rating and application, including at least the following : a) Function, e.g., Over-current, Under-voltage b) Model and version, e.g., REL561 V1.2, 7VK512 V1.0 c) Serial number d) Nominal input ratings of D.C voltage, A.C current and A.C frequency

12.4.2 Protection Scheme Policy All Main, Backup, Control and auxiliary relays shall be limited to the TNB Accepted Relay List. All the relaying code shall follow the protective device codes.

1122..44..22..11 OOvveerrhheeaadd LLiinnee FFeeeeddeerr PPrrootteeccttiioonn The overhead line shall be protected against faults and equipped with appropriate auto-reclosing facilities to reduce the outage period. The overhead lines shall be protected as tabulated in the following Table 12.1.

Table 12.1: Distribution overhead line feeder protection requirements

Voltage Route length Scheme 33kV and below (outgoing feeder)

> 2 downstream substation

1. Main unit protection [87CC or 87CD] 2. Backup Over-current and Earthfault protection [50OC

+ 50EF + 51OC + 51EF]

< 2 downstream substation

1. Main Over-current and Earthfault protection [50OC + 50EF]

2. Backup Over-current and Earthfault protection [51OC + 51EF]

All Main protection relays shall be able to initiate auto-reclose cycle. For distribution network, auto-reclose shall also be initiated by Backup protections. A scheme for live line maintenance purposes shall be also incorporated. In addition, for 33kV system and below, direct optical fiber connections shall be applied.

1122..44..22..22 UUnnddeerrggrroouunndd CCaabbllee FFeeeeddeerr PPrrootteeccttiioonn The underground cable shall be protected against severe damage caused by faults and insulation breakdown. The functional scheme for underground cable feeder protection is tabulated as in Table 12.2.


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Table 12.2: Distribution underground cable feeder protection requirements Voltage Scheme

33kV and below (outgoing feeder)

1. Main unit protection [87CC or 87CD]

2. Backup Over-current and Earthfault protection [51OC + 51EF]

Unit protection relays shall have sufficient contacts to initiate the Breaker failure protection and other protection, control and signaling function and optical fiber shall be used for new installation.

For Aerial Bundle Cable (ABC) installation, it shall be treated as underground cable feeder. In addition, direct optical fiber shall be used for tele-protection, while no auto-reclose scheme shall be applied for underground cable feeder protection.

1122..44..22..33 TTrraannssffoorrmmeerr PPrrootteeccttiioonn Transformer protection is required to prevent any damage to transformer and all associated equipment for all internal electrical and mechanical faults, and to minimize the loss of life due to over-excitation. Types of transformer protection and its associated protection can be categorized as tabulated in Table 12.3.

Table 12.3: Transformer protection requirements

Type Protection scheme Control scheme Power Transformer (33-22)/11kV

1. Main Unit protection [87TBD] 2. Mains Transformer Guard protection

[26OT + 26WT + 63BT + 63 TCBT + 63PRD] [26OA + 26WA + 63BA +71OLL]

3. Main Restricted Earthfault protection [64REF/LV]

4. Backup Over-current and Earthfault protection

[50OC + 51OC] HV side [51OC + 51EF] LV side 5. Backup Standby Earthfault protection

[64SBEF2]

Automatic Voltage controller

Earthing Transformer

1. Main Transformer Guard Protection

[63BT] [63BA + 63PRD + 71OLL] 2. Backup Standby Earthfault protection [64SBEF2]

Automatic Voltage Controller, where required

Local Transformer

1. Backup Over-current and Earthfault

protection [51OC + 51EF]

Automatic Voltage Controller, where required


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All other interconnecting equipment such as power cable etc, to the transformer shall be protected by their relevant protection scheme. All Main protection relays shall be dedicated, independent from any other relays except for over-excitation protection relay. In addition, alarm and tripping indications for all types of transformers shall be separated. The LV side of earthing and local transformers shall be protected by suitable rated fuses.

1122..44..22..44 BBuussbbaarr PPrrootteeccttiioonn Busbars shall be adequately protected and the Busbar zone of protection shall be provided for each busbar section in any busbar configuration system. Table 12.4 describes the functional details of the required Busbar protection scheme.

Table 12.4: Busbar protection requirements Voltage Level Functional scheme Busbar Type 33kV, 22kV and 11kV.

Reverse blocking scheme or 87BBHI

Gas Insulated Substation (GIS)

Reverse blocking scheme or Arc protection relay

Air Insulated Substation (AIS)

Intertripping scheme to the remote end shall be provided for complete clearing of faults, where it is required. In addition, the D.C supply for the Busbar protection scheme at the busbar protection panel shall be separated from other protection schemes.

1122..55 CCoooorrddiinnaattiioonn bbeettwweeeenn DDGG aanndd DDiissttrriibbuuttiioonn PPrrootteeccttiioonn For the distribution system with the DG to operate safely and reliably, the protection devices in both systems must be properly coordinated. With the connection of a generator, the fault current contribution and distribution would change significantly requiring detailed analysis and resetting/coordinating the protection devices.

It is only proper that coordination study be carried out to verify the proper operation of the protective equipment. The following general procedure should be followed:

Initially, the DG should submit proposed setting of all relays given the interface short-circuit contribution from the utility. The DG should set all the protective relays for the protection of their installation disregarding any coordination with the utility system. The report to the utility should include: a) Protection philosophies adopted; b) Short-circuit limits including making and breaking capacities of equipment - breakers,

cables, lines etc.. c) Transformer heat withstands capability; d) Generator limits - reactive, active power, field current and voltage limits, over-speed

and under-speed; etc.. e) Documents on characteristics of the relays and fuses employed;


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f) Information on breaker operating time; g) Proposed settings/coordination curves (if applicable) and the reasons for the chosen

setting; and h) Other important limits required of the utility.

The utility perform coordination with the generator interconnected and the report should include: a) The proposed setting and their coordination; and b) Changes required on the DG plant relay settings and the reason for the changes.

1122..66 SSCCAADDAA//DDAA RReeqquuiirreemmeennttss

12.6.1 Basic SCADA Supervisory Control and Data Acquisition (SCADA) SCADA systems consist of one or more computers with appropriate applications software (Master Stations) connected by a communications system (wire, radio, power line carrier or fiberoptics) to a number of remote terminal units (RTUs) placed at various locations to collect data, remote control, and more recently perform intelligent autonomous (local) control of electrical systems and report results back to the remote master(s). SCADA systems are used for fault identification, isolation and service restoration, breaker control, recloser blocking, generator control, feeder switching and reconfiguration, line switching, voltage control, load management, automated meter reading (AMR), archiving processes, automatic generation control (AGC), dispatch accuracy feedback, economic dispatch, energy purchased and sold, system load, system emulation, capacitor bank switching, monitoring voltage regulators, transformer temperature, as well as metering power functions. (For additional discussion, see also Chapter 25 in the Standard Handbook, “Computer Applications in the Electric Power Industry”).

Remote Terminal Units (RTU) RTUs are special purpose computers which contain analog to digital converters (ADC), digital to analog converters (DAC), digital inputs (status) and outputs (control). RTUs are ruggedly constructed; inputs and outputs are fully protected against spurious electrical transients per the surge withstand capability (SWC) test specified by IEEE Std. 472 and ANSI Std. C37.90a. RTUs are designed for an extended temperature environment (-40 to +85°C) expected of the electric utility environment. RTUs are designed to be powered by 120/240 Vac or 24/125 Vdc substation battery. An RTU may have multiple communications ports so that more than one master station can share the RTU.

12.6.2 SCADA Practices in TNB and Requirements TNB distribution system will be SCADA ready by 2007. All the control centers will be equipped with SCADA facilities for supervisory control. Recognizing that the operation of any DG Plant would become an important feature of distribution operation, all DG Plants interface/connection are to be equipped with SCADA facilities, that is, SCADA-ready prior to commissioning of the plant. The SCADA facilities required are as follows:- Remote Terminal Units (RTU) c/w Marshalling cubicle;


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Communication system from the DG Plant to TNB designated control centre. 1 nos. of RTU complete with marshalling cubicle is required to be placed at the point of connection/interface. All necessary interface modules to the RTU used for measurement purposes such as transducers shall be fixed. The RTU shall be provided by the DG Developer. TNB will provide the necessary functional and detailed specifications as well as the approved models/make. The RTU will be commissioned during commissioning of the DG Plant interface connection. The RTU shall be maintained by the DG Plant Operator.

The RTU shall measure / record the following :- 1) Frequency (Hz) 2) Voltage ( Volts) 3) Current (Amps) 4) Power factor 5) Real Power Energy flow (MW) 6) Reactive Power Energy flow (MVAr) and any other measurements deemed necessary by TNB. If required, remote control shall be able to be executed via the RTU on all switches that are in TNB’s jurisdiction/area of responsibility

The communication system between the generator plant where the RTU is located and TNB could be via wire or wireless configuration. Wire configuration shall include lease lines or telephone lines. Wireless configuration shall include via microwave, satellite or GSM. The mode of communication to be used shall depend on the siting of the generator plant, capacity of the generator plant and/or distance of the generator plant to the nearest TNB main substation (PMU or PPU). Lease line is the preferred option by TNB. Nevertheless, TNB will advice the generator plant of the mode of communication to be used.

12.6.3 Master System The following data shall be required to be submitted to TNB for the purpose of TNB Network Application installed in the Master System:

For each interface Transformer: • Rated voltage (kV) for every winding • Rated Apparent power (MVA) • Impedance voltage drop (%) • Short circuit (Copper) loss (kW) • No load loss (kW) • No load current loss (%) • Earth possibility • Short circuit resistance (ohm) • Short circuit reactance (ohm) • No load resistance (ohm) • No load reactance (ohm) • Vector group

For each generating unit: • Nominal voltage


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• Bus type (PV or PQ) • Rated Voltage (kV) • Rated apparent power (kW) • Ratio delta P /delta f for equivalent governor model (kW/Hz) • Rated power factor • Sub-transient reactance (%) • Stator resistance (%) • Zero sequence reactance In the case that TNB has to control the generator, the master system installed does not cater for AGC (automatic generator controller). Therefore, if TNB has to develop this function and any other associated function in order to meet the requirement, TNB requires that 10% of the development cost to be charged to the plant generators

1122..66..33..11 MMaasstteerr SSttaattiioonn.. The SCADA Master Station, which monitors and controls RTUs and their attached electric apparatus, is no longer a turn-key custom product. The graphics capabilities of the modern workstations (and to a limited extent PCs) generally results in a man/machine interface (MMI) that makes it possible for the operator to easily deal with a variety of systems without sensory overload. The Master Station has a core program which is called the operating system. Running on the operating system are the applications programs written by the utility or the SCADA vendor. Dynamic data exchange (DDE) mechanisms in the operating systems allow the computer to link automated mapping/facilities management (AM/FM) databases to the SCADA system. The Master Station can not only monitor and control RTUs but can call up customer records from a networked billing computer, a map of the affected area from an AM/FM database on the mapping system. Artificial intelligence programs will be able to filter alarms and perform corrective actions without operator intervention. The ability to call up multiple databases in conjunction with SCADA alarms allows for more efficient maintenance crew callouts when trouble occurs. PC Based Systems. The most common Master Station today is the ubiquitous IBM PC compatible microcomputer with either Microsoft or IBM DOS, IBM OS-2 or Microsoft Windows disk operating system. PCs can be networked so the processing and displays can be distributed either for multiple users or to share tasks. True multi-tasking (running several independent programs in parallel) on a single PC is only possible with OS-2. There are also several variants of Unix that are PC compatible but their use in SCADA is minimal. The PC VGA display screen (the highest standard available for the PC) is considered a medium resolution device. While there are special drivers and video boards to enable non-standard higher resolution modes, such components require special software drivers. Mouse or trackball cursor pointer support is optional as is a LAN system such as Ethernet.


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1133.. AAppppeennddiixx GG:: CCoonnnneeccttiioonn aaggrreeeemmeenntt

1133..11 GGeenneerraall This appendix outlines the possible technical contents of ‘Connection Agreement’ or ‘Connection Operation Manual’ to be established and agreed by both the DG Operator and TNB. The connection agreement will contain both commercial and technical sections and information related to the connection of the DG plant. This appendix contains a list of possible technical information on the DG plant and the network that the DG is connected to. Generally, this information should describe the ‘as installed’ plant.

1133..22 CCoonnnneeccttiioonn AAggrreeeemmeenntt Examples of data required for the connection agreement include:

13.2.1 Description of Facility and Site.

13.2.1.1 This section describes the DG plant and its auxiliaries and may include the following: 13.2.1.2 Electrical system diagram – The electrical system diagram should be a high level diagram

showing the electrical system at the connection point, such as a single line diagram. 13.2.1.3 Machine Data – This should include all the relevant machine capability and data such as:

Data on the turbine Manufacturers and test data of generator impedances and time constants, mechanical. Block diagrams of all controls and model parameters Excitation capability Protection settings and grounding Settings of each protective device Grounding types and values Generator Transformer data including tap changing facilities

13.2.1.4 Fault level contribution – The fault level infeed into the network should include

contribution from generators and any induction motors. 13.2.1.5 Auxiliary system data – Data on large items of equipment should be included such as

large motors, switchgear capability, auxiliary transformers and interconnecting cables. 13.2.1.6 Control settings – control settings such as interlocking systems, synchronizing systems

should be described and where necessary details provided.


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13.2.1.7 Operating regime - The DG plant operating regime should be described and may include description of: • Short term Parallel to network • Intermittent operation • Continuous operation • Standby generation

13.2.2 Design & Operations Standard 13.2.2.1 List of standards used in the design of the facility and network. It is important that the

current revisions of the standards at the time of design and installation are stated.

13.2.3 Energy Accounting and Metering Equipment.

13.2.3.1 The metering system should be described. Metering locations and a single line diagram

should be included. The description should include: - Main and Check Meters - MW and Mvar meters - Operational and Tariff Metering

13.2.4 Interconnection Facilities. 13.2.4.1 This section should list out the technical conditions and any agreed requirements for the

connection. Items include: 13.2.4.2 Permitted Max Export

Maximum MW Maximum Mvar

13.2.4.3 Excitation Controls – The agreed control regime including agreed settings where

appropriate such as Power Factor Voltage control Var Control

13.2.4.4 Constraints – Agreed constraints and description of the conditions for constraints should

be included here. If the connection has firm and/or non firm offers, the conditions of each should be described.

13.2.4.5 Max Import – If necessary, the agreed levels of imports, such as Standby and Top Up

supplies should be included. Where necessary, the conditions for the agreed levels may be included. The levels should include Maximum MW and Maximum Mvar.


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13.5.2 Communication Facilities 13.5.2.1 This section should describe all the communication facilities and the list of available

indications and control points. It should also include any voice communication equipment. Items may include:

• SCADA control points • Remote indications • Output dispatch controls if any

13.5.3 Electricity Characteristics. 13.5.3.1 This section describes the Distribution network characteristics and should include items

such as:

13.5.3.2 System limits Operating Voltage Operating frequency Harmonics

13.5.3.3 Maximum Network Design System fault levels – This is normally the designed capability

of the Distribution network at the point of connection. Normal configuration Outage configuration

13.5.3.4 Current System Fault Levels – This is the normal fault level at the connection point. It

should be made clear whether this fault level includes the DG plant. Normal Configuration Outage Configuration

13.5.3.5 System Drawing – a system drawing such as a single line diagram at the connection point

should be included. It should have sufficient details as necessary, including protection system details relevant to the DG plant.

13.5.3.6 Interface protection system – The network protection system relevant to the connection

point should be described. It should include any interlocking facilities implemented. 13.5.3.7 Operating limits – Any other agreed operating limitations should be described. This may

include description of operation such as short term paralleling operation. 13.5.3.8 Auto-reclosing facilities – Any auto reclosing facility that may affect the DG plant should

be described.


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1133..33 CCoonnnneeccttiioonn OOppeerraattiioonn MMaannuuaall.. The operation agreements should include section such as: • Brief description of how network maintenance and DG plant maintenance is to be communicated. • Any interim operational arrangements. • Supply restoration following a network disturbance. • Communicating daily dispatch. • Safety procedures.