Main Transmission System Planning Guideline

Transcription

1 Main Transmission System Planning Guideline February, 2005 Page i Rev /04/04

2 NOTICE COPYRIGHT 2000 TRANS POWER NEW ZEALAND LIMITED ALL RIGHTS RESERVED The information contained in the report is protected by copyright vested in Trans Power New Zealand Limited ( Trans Power ). The report is supplied in confidence to you solely for your information. No part of the report may be reproduced or transmitted in any form by any means including, without limitation, electronic, photocopying, recording, or otherwise, without the prior written permission of Trans Power. No information embodied in the report which is not already in the public domain shall be communicated in any manner whatsoever to any third party without the prior written consent of Trans Power. Any breach of the above obligations may be restrained by legal proceedings seeking remedies including injunctions, damages and costs. LIMITATION OF LIABILITY/DISCLAIMER OF WARRANTY Trans Power make no representation or warranties with respect to the accuracy or completeness of the information contained in the report. Unless it is not lawfully permitted to do so, Trans Power specifically disclaims any implied warranties of merchantability or fitness for any particular purpose and shall in no event be liable for, any loss of profit or any other commercial damage, including but not limited to special, incidental, consequential or other damages. TABLE OF CONTENTS Page ii Rev /04/04

3 1. INTRODUCTION RELIABILITY DEFINITION CRITERIA Single contingency criterion Maintenance outage... Error! Bookmark not defined. An underlying assumption of the N-1 criteria is that maintenance is carried out during times of light load.... Error! Bookmark not defined Multiple contingency Sub-station arrangement RELIABILITY ASSESSMENT Load Dispatch STEADY STATE PERFORMANCE CRITERIA EQUIPMENT RATINGS Grid owner equipment Generating Unit Rating VOLTAGE QUALITY Normal Steady State Voltage Step Change in Voltage - Dynamic SHORT CIRCUIT LEVELS STABILITY CRITERIA TRANSIENT STABILITY Disturbances selected for testing Auto-reclose of Circuit Breakers Fault Clearing Time Transient Voltage Performance Criterion Over-voltages due to Load Rejection DYNAMIC STABILITY VOLTAGE STABILITY FREQUENCY STABILITY... ERROR! BOOKMARK NOT DEFINED. APPENDIX A: SECURITY CRITERIA APPENDIX B: INFREQUENT SWITCHING CRITERIA APPENDIX C: TRANSIENT STABILITY DISTURBANCES APPENDIX D: DAMPING CRITERIA FOR DYNAMIC STABILITY Page iii Rev /04/04

4 1. Introduction The purpose of transmission system planning is to develop a reliable and efficient transmission system for transferring power from areas of generation to areas of demand (load) under varying system conditions, while operating equipment within accepted ratings. The system conditions include - changing demand patterns, generation changes and equipment outages (planned or unplanned). The planning process involves applying a number of criteria: technical, economic, environmental and safety to the current or future transmission system. This document sets out the technical criteria to be applied in planning the main transmission network. While this document is focused on technical criteria only, readers are reminded that any proposed transmission development must also consider all other planning aspects such as environmental, economic, etc. The technical criteria used in transmission system planning can be divided into three main categories, which are covered in this Guideline as per Table 1.1: Table 1.1: Technical Criteria Category Defined as Section System reliability Is the system adequate and secure? 2 Steady state Is the normal operating state of the system 3 performance within prescribed limits? Stability Does the system remain normal or return to normal following a disturbance? 4 Additionally, for comparison purposes, the Appendices provide an international context to the standards and criteria that Transpower applies in meeting each of these activities. 2. System Reliability 2.1 Definition The accepted definition of transmission system reliability incorporates assessment of two basic aspects of the system - adequacy and security. The National Electricity Reliability Council, USA (NERC) 1 has defined these terms to mean: Adequacy The ability of the electric systems to supply aggregate electrical demand and energy requirements of their customers at all times, taking into account scheduled and reasonably expected unscheduled outages of system elements; and Security The ability of the electric systems to withstand sudden disturbances such as electric short circuits or unanticipated loss of system elements. 1 The National Electricity Reliability Council oversees and co-ordinates reliability and security for the entire United States. Page 1 Rev /04/04

5 2.2 Criteria Transpower uses a deterministic approach to planning. This approach is consistently applied in most transmission networks throughout the world. 2 The deterministic planning criteria uses N, (N- k ) terminologies to describe the service level for which a system is planned, where k is the number of elements out of service at any one time. These terms are defined as follows: (N) criterion denotes that the system is planned such that with all transmission facilities in service the system is in a satisfactory state and loads may have to be shed to return to a satisfactory state for a credible contingency event. It could be said that an N security policy results in a system that is not secure against contingent events. (N- k ) criterion denotes that the system is planned such that with all transmission facilities in service the system is in a secure state and for any k credible contingency event(s) the system moves to a satisfactory state. If any further contingency events were to occur loads may have to be shed to return to a satisfactory state Single contingency criterion The main interconnected transmission system shall be designed to maintain N-1 security criterion, meaning that the system is in a secure state with all transmission facilities in service and in a satisfactory state under credible contingent events. N-1 is a common security standard in many countries including Australia, Ireland, Denmark and France 3. The single contingencies to be considered under an N-1 criterion are: loss of a single transmission circuit loss of a single generator loss of an HVDC pole loss of a single bus section loss of an interconnecting transformer loss of a single shunt connected reactive component, e.g. capacitor bank, SVC The loss of an element could be either planned (as part of scheduled maintenance) or unplanned (as an unforeseen event) either by inadvertent disconnection or as a consequence of a fault occurring in/on the affected element Maintenance outages An underlying assumption of the N-1 criteria is that maintenance is carried out during times of light load so that the risk and consequences of an interruption due to unforseen events is minimised. 2 A 1992 survey by CIGRE confirmed that of 24 countries participating, all used the deterministic criteria 3 Refer to Appendix A for further detail. Page 2 Rev /04/04

6 2.2.3 Multiple contingency The risk and consequences of less frequent but more extreme credible contingencies must also be investigated to determine what emergency measures may be required to minimise the consequences and provide for restoration of supply in the shortest possible time Sub-station arrangement The sub-station arrangements are chosen to satisfy all the reliability performance criteria set out in this guideline while allowing for future extensions and maintenance. 2.3 Reliability Assessment Reliability is assessed by simulating performance of the system with all transmission facilities in service and then applying credible contingencies to the simulation, while generation and load patterns are varied to determine whether a satisfactory state for the system may be maintained for the various generation and load patterns Load All simulation studies shall be performed for system peak load conditions for both summer and winter periods. Studies may also be performed for light load conditions where required. These latter studies may be necessary, for example, where experience has identified that certain system issues arise only under light or trough load conditions. If a part of the system is radial, the studies for the radial part of the system must be carried out for peak load conditions for that area Dispatch Simulation studies shall be carried out for the worst case credible generation dispatch scenarios. For hydro generation (New Zealand s main source of electricity), these include dry, average and wet hydrological scenarios. 4 Studies shall also be carried out for extreme dry scenarios to identify emergency measures that may have to be put in place. 4 These have been developed within Transpower using information from a number of sources including NIWA Page 3 Rev /04/04

7 3. Steady State performance The steady state criteria apply to normal operating conditions and to post-disturbance conditions once the system settles to new operating conditions. The steady state performance criteria for planning are: Primary transmission equipment must operate within normal ratings when all transmission facilities are in service. Primary transmission equipment must operate within acceptable short term ratings during contingencies. There is no load curtailment required to maintain N-1 security level for any operating condition. Voltage quality is maintained as set out in section 3.2 Cascading outages do not occur. 3.1 Equipment Ratings Grid owner equipment The grid owner equipment ratings used are drawn from Transpower s Asset Capability Information (ACI) database. The ratings for equipment in this database are in accordance with Transpower policy document TP.GG on equipment ratings, which take into account manufacturer s recommendations, the age of equipment and local environmental conditions. The database includes all transmission equipment: lines, transformers, switchgear, protection and reactive equipment - synchronous condensers, capacitors, reactors and SVCs Generating Unit Rating The rating of all generating units connected to the grid shall be the ratings provided by the Generators as part of their Asset Capability Statement provided to Transpower ( as the Grid Owner). 3.2 Voltage Quality The criteria for voltage in steady state operation are defined by limits set for different conditions: Normal steady state voltage Step change in voltage Sustained steady state voltage (after tap changing, Reactive Power Controller and other dynamic sources actions ) These are discussed in the following subsections. Page 4 Rev /04/04

8 3.2.1 Normal Steady State Voltage The normal steady state voltage at buses shall be as specified in Table 3.1 or as stipulated in the contract agreement with the customer. Table 3.1 is consistent with the steady state voltage limits as prescribed in Rule 3.1, Section III, Part C of the Electricity Governance Rules and Regulations (EGRS). Table: 3.1 Voltage Limits During Normal Conditions Nominal Voltage (kv) Maximum Voltage (kv) Minimum Voltage (kv) Step Change in Voltage - Dynamic The voltage step change is the dynamic voltage change between the pre-switching voltage and the prevailing voltage in the period immediately after transient decay and AVR action but before any manual or slow control action e.g. manual tap changing, automatic tap changing, manual switching of capacitor banks under normal operating conditions. The allowable voltage deviation depends on the frequency of switching infrequent or routine Routine Switching The Australasian standard 5 for acceptable voltage deviation during routine switching is set out in Table 3.2: Table 3.2 Allowable Dynamic Voltage Deviation r no of events per hour Vdyn/Vn (%) MV HV r < r < r < r Note: MV refers to 1 kv < V N 35 kv MV refers to 35 kv < V N 230 kv Vdyn/Vn Maximum voltage change for normal operating conditions The voltage change at buses for routine switching of equipment to control voltage (e.g. switching of capacitor banks or circuits) must not exceed the value given in Table 3.2. Currently Transpower plans on the basis of a 2% voltage dip for routine switching - this is slightly more conservative than set out in the AS/NZS standard. 5 Australian/New Zealand Standard - AS/NZS :2001, Page 5 Rev /04/04

9 Infrequent switching There are no standards specifying the allowable voltage deviation for infrequent switching, but it would naturally be greater than for routine switching operations. Transpower has designed the system based on a 5% variation. Worldwide, the allowable voltage deviation is 5% to 6% depending on the utility Short circuit levels The default planned maximum short circuit levels are shown in Table 3.3. There are a limited number of locations, such as Otahuhu 110 kv and Islington 66 kv buses, where the maximum fault levels will exceed the default maximum short circuit levels shown, and these are documented in other Grid Owner documents. Table Maximum Short Circuit Power and Current Limits Nominal Voltage Maximum short-circuit Power and Current Limits kv MVA ka , , , , , Stability Criteria The stability of a power system is determined by its ability to remain stable when the system is subjected to any disturbance. It can be further divided into four categories of stability: Transient Stability Dynamic Stability Voltage Stability Frequency Stability. These are discussed in the following subsections. 4.1 Transient Stability Transient stability refers to the ability of the system to maintain synchronism when it experiences large disturbances like a line fault or loss of a generator. 6 Refer to Appendix B for further information Page 6 Rev /04/04

10 4.1.1 Disturbances selected for testing A key input into assessing transient stability is identification of the most severe disturbance on the system. Transpower has identified 7 types of significant disturbance, from which the most severe disturbance must be identified. The seven disturbance types are: (1) a 3-phase fault on a circuit close to a substation cleared in main protection clearance time by opening the circuit breakers at each end of the circuit to disconnect the circuit (2) a 3-phase fault on a circuit close to a substation cleared in main protection clearance time by opening the circuit breakers at each end of the circuit and reclosing on fault with subsequent reopening of the circuit breakers at each end to disconnect the circuit (3) a 3-phase fault on a transformer followed by disconnection of the transformer (4) a 3-phase fault on a bus section cleared by the bus zone protection operation of all circuit breakers connected to the faulted bus section. (5) a single-phase-to earth fault on a circuit cleared by the back-up protection operation of the circuit breakers at each end of the circuit. (6) a single-phase-to earth fault on any circuit cleared by circuit breaker failure protection of the relevant back-up circuit breakers. (7) a sudden disconnection of any plant including a generating unit This list of disturbances is similar to those used by overseas utilities. Refer to Appendix C for more detail Auto-reclose of Circuit Breakers Automatic reclosing may be employed on all transmission lines to enhance security. However, the system must be planned such that the system is stable without reclosure. The system must also be tested for stability with unsuccessful operation of the auto re-closing facility. If the studies show that fast re-closure onto a fault makes the system unstable, the dead time may be increased sufficiently to make the system stable. Alternatively, auto-reclose may be enabled for a single-phase fault and disabled for a 3-phase fault. Autoreclosing at line terminals that are in electrical proximity to turbine-generators may subject them to excessive shaft torque and winding stresses with resultant loss of life. These effects should be evaluated before autoreclosing is applied. Autoreclosing a region (with only one substation or group of substations) connected to the main transmission grid through a single circuit with no generators or limited generation in the region can cause voltage and/or frequency disturbances. There is a possibility of sustained low voltage or even voltage collapse depending on the type of load and the amount of load. These effects should be evaluated fully before applying auto reclosures. Page 7 Rev /04/04

11 4.1.3 Fault Clearing Time Where the exact fault-clearing times are not known, the following fault clearing times shall be used in simulation studies: Main protection for 220 kv circuits: 120 msec. Main protection for 110 kv circuits: 200 msec Main protection for 66 kv circuits: 200 msec CB failure time: 350 msec Transient Voltage Performance Criterion The performance criteria for transient voltage performance for large disturbances are: For single contingencies, the transient voltage dip after the fault is cleared should not exceed 25% at load buses or 30% at non load buses. Furthermore, at load buses, voltage dip should not exceed 20% for more than 20 cycles. For multiple contingencies, the transient voltage dip after the fault is cleared should not exceed 30% at load or non-load buses. Furthermore, at load buses, voltage dip should not exceed 20% for more than 20 cycles. This criteria has been adopted from the Western Electricity Co-ordinating Council 7 (WECC) planning standard, which is also applied in Western Australia Over-voltages due to Load Rejection Power frequency over-voltages due to load rejection must be limited to values within the over voltage envelope shown in Figure 4.1 Figure 4.1 Acceptable Overvoltage Envelope Post-Disturbance Voltage Ratio = Pre-Disturbance Voltage pu pu 3 Cycles Time(Cycles) 7 Formerly the Western System Coordinating Council. Represents at least 40 electricity providers on the Western seaboard of North America from Canada through to northern Mexico. Page 8 Rev /04/04

12 4.2 Dynamic Stability Dynamic stability refers to the ability of a power system to withstand small changes in loads, switching of lines and also to return to a satisfactory state following large disturbances like a line fault. The main problem in dynamic stability is with electromechanical oscillations of increasing amplitude between generators, causing generators to lose synchronism unless there is positive damping of these oscillations. The damping criterion set by Transpower is that the oscillations must decay within 12 seconds (settling time). If oscillations do not settle within the time specified, appropriate measures must be taken to damp the oscillations. The 12 second decay time is similar to that used by most other utilities. Refer to Appendix D for more information. 4.3 Voltage Stability Voltage stability refers to the ability of the system to maintain voltage at all buses under steady state conditions, for any disturbance, such as a variation in load or an outage of circuit(s). During periods of voltage instability, voltage drops progressively, leading to low voltage throughout the system/region. When voltage throughout the system/region reaches and stays at low values, the system is considered to have reached voltage collapse. How near the system is to voltage instability can be assessed on the basis of real and reactive power margins for the system or particular region concerned. Note that the voltage stability margin may not always be a reliable indicator. For example in a heavily reactive power compensated system, instability can occur even at high voltages. There are no international standards on acceptable real or reactive power margins, as this depends very much on the system. The criteria adopted by Transpower are drawn from the Western Electric Co-ordinating Council (US) 8 report and are based on Q-V and P-V analyses. They are: i) For the outage of a single element, (a generator, circuit, transformer or any reactive source), the real power (MW) margin must be 5% as measured from the nose point of the P-V curve. ii) The reactive power (Mvar) margin at the most reactive-deficient bus must have an adequate reactive power margin for the worst single contingency, to satisfy either a 5% increase beyond maximum forecast loads or a loss of reactive support close to the bus that is considered most susceptible to voltage collapse and for which the Q-V plots are derived. The worst single contingency is the one causing the largest decrease in the reactive power margin. iii) For outage of a bus section or for a double contingency, the MW margin must be 2.5% as measured from the nose point of the P-V curve. iv) The reactive power (Mvar) margin at the most reactive-deficient bus must have an adequate reactive power margin for the loss of a bus section or a double contingency at 50% of that required for the worst single contingency. 8 Formerly the Western System Co-ordinating Council Page 9 Rev /04/04

13 v) Adequate dynamic reserve should be provided to ensure that voltage during the transient period does not result in a sustained voltage collapse. The static analysis must be supplemented by a limited number of dynamic studies to establish that the static approach is satisfactory. In the dynamic analysis, the effect of generator over-excitation limiters, transformer taps, induction motors, etc should be represented in detail. Page 10 Rev /04/04

14 Appendices Page 11 Rev /04/04

15 Appendix A: Security Criteria Introduction The security criteria adopted by international utilities have been identified by reviewing published papers and by direct correspondence. Generally utilities adopt N-1 or N-2 security criteria for the main transmission grid. Many of the utilities use N-1 security criterion for the main grid and N-2 security criterion for critical loads. The degree to which the transmission networks are meshed and the availability of generation within regions of the transmission network are important factors in determining the appropriate security criteria for a region. Table A.1 gives a comparison of security criteria used by some of the major utilities in the world. More detail can be found in the following country sections. Table A.1 Comparison of Security Standard Utility Security Criterion Remarks Transpower N-1 Maintenance to be carried out at appropriate time without violating N-1 security criteria NECA, Australia N-1 Western Australia N-2 When circuit is out on maintenance, the system is planned to meet only 80% of the demand WECC, USA N-2 No loss of demand. Allows for simultaneous outage of two elements with planned outage of an element but with some load shedding NGC, UK N-2 N-1, N-2 N-2 For the main transmission system A mix of N-1 and N-2 for specific regions, depending on demand Ireland, Belgium, Denmark, N-1 CIGRE 1992 Survey (meshed system with interconnection to neighbouring countries) Finland, France Brazil N-1 Italy N-2 CIGRE 1992 Survey ESB, Ireland N-2 Loss of load is allowed for maintenance events Australia All the Australian utilities, except Western Australia follow the National Electricity Code (NEC) which specifies that the network must be planned, operated and maintained so that it is capable of withstanding any single credible contingency event. The code allows for higher standards to be adopted where appropriate due, for example, to the size and importance of the customer groups. Western Power, Western Australia, specifies N-1 security criterion to meet peak load and (N-2) security criteria to meet 80% of load. Supply to CBD Sydney CBD is supplied by TransGrid over the 330 kv and by Energy Australia over a large 132 kv cable network. The security standard adopted for supply to the CBD allows for the simultaneous outage of a TransGrid 330 kv cable into Sydney and any 132 kv cable or 330/132 kv transformer within the Energy Australia Network. It Page 12 Rev /04/04

16 also allows for outage of any section of a 132 kv busbar. It does not allow for the outage of two 330 kv cables, as this is considered too costly. Supply to the Melbourne and Adelaide CBD s are designed to meet N-2 criteria. The 110 kv supply to the Brisbane CBD is being planned so that full supply is maintained with two 110 kv cables out of service. United States - Western Electric Co-ordinating Council (WECC), WECC also uses (N-2) criterion for planning the transmission grid. However, there are some differences in defining contingencies: WECC considers bus section outage as a double contingency not a single contingency. WECC allows for unplanned outage of two elements with planned load curtailment or shedding but does not specify the percentage of load that is met under such conditions. United Kingdom - National Grid Company (NGC) The security standard adopted by NGC for the main interconnected transmission system is (N-2). However, there are significant differences between the NGC system and the New Zealand system; the NGC system is heavily meshed with generation in diverse areas, whereas the New Zealand system is comprised of a weak, longitudinal transmission with significant generation located in a few areas, remote from the demand. In addition, the NGC demand is around 10 times that of NZ and due to its density, there are generally alternative supply options to any grid off-take, via the distribution networks, which means the restoration times can be reduced. Table A.2 Security Level for Group Demand Group Initial System Condition Demand Intact System With Single Arranged Outage Over 1500 MW In accordance with main interconnected transmission system planning criteria Over 300 MW To 1500 MW Over 60 MW To 300 MW Immediately No loss of supply Note 1 Immediately Group Demand minus 20 MW Note 2 Within 3 hrs No loss of supply Immediately Maintenance Period Demand Within time to restore arranged outage Group Demand Within 3 hrs Smaller of (Group Demand minus 100 MW) and 1/3 Group Demand. Within time to restore arranged outage Group Demand Page 13 Rev /04/04

17 Up to 60 MW Within 15 min Smaller of (Group Demand minus 12 MW) and 2/3 Group Demand Within 3 hrs No loss of supply Nil Note 1 The maintenance period demand is 67% of the group demand. Note 2 The group demand are the forecast maximum demand. The NGC also defines separate planning criteria for areas of grouped demand. The security standards for these areas is such that, for an outage of any of the following: a) A single transmission circuit; or b) A single transmission circuit with a single arranged outage of another transmission circuit, generating unit or any reactive supporting equipment, any loss of supply shall be in accordance with Table A.2. Ireland - ESB National Grid ESB National grid plans their system for N-2 security criteria. However, they allow for some loss of load for an unplanned outage when another transmission element is on planned outage. International Surveys CIGRE published a report in 1992 on a survey carried out on standard used in transmission planning. Twenty four countries participated in this survey. The findings from the survey are: All countries use deterministic technique for planning. In addition about half use or have probabilistic techniques available. The number of countries that use (N-2) criterion just exceeds the number that use only an (N-1) criterion. However, the definition of (N-2) criteria and its application varies. Some countries consider the outage of double circuits only (not any two circuits); some do not apply the criteria at peak load conditions; and some apply it only for critical loads. Those countries that use N-2' criterion do not also consider the outage of a busbar. 10 of the 24 countries (Brazil, Canada, UK, USA, South Africa, etc) use additional transfer requirements for zones or groups of circuits. Page 14 Rev /04/04

18 Appendix B: Infrequent Switching Criteria Australia Western Australia uses +/-6% voltage change for infrequent switching whereas the regulator overseer - NEC does not make any specific distinction between routine and infrequent switching. Specifically, the NEC code specifies in Clause S5.3.7 that voltage should not exceed the following limit: Where only one Distribution Network Service Provider or Customer has a connection point associated with the point of supply, the limit is 80% of the threshold of perceptibility set out in Figure 1 of AS2279 Part 4; or Where two or more Distribution Network Service Providers or Customers causing voltage fluctuations have a connection point associated with the point of supply, the threshold of perceptibility limit is to be shared in a manner to be agreed between the Distribution Network Service Provider and the Code Participant in accordance with good electricity industry practice. Ireland ESB National Grid (Ireland) allows step voltage changes of 3% for capacitor bank switchings with all transmission facilities in service. It does not specify any step voltage change for infrequent switchings. Page 15 Rev /04/04

19 Appendix C: Transient Stability Disturbances Australia All Australian utilities except Western Power (WA), follow the National Electricity Code in planning their system. The NECA specifies the following disturbances for planning the system: Disconnection of any single generating unit with or without application of a fault Disconnection of any transmission line, with or without the application of a single circuit two-phase-to-ground solid fault on lines operating at or above 220 kv, and a single circuit three-phase solid fault on lines operating below 220 kv. Western Power specifies the following disturbances for planning the system: A three-phase-to-ground fault cleared by main protection A single phase fault cleared by backup protection Single phase auto-reclosing of lines Tripping of lines or transformer without a fault United States The Western Electricity Coordinating Council (WECC) 9, USA specifies the following disturbances for planning the system: a) Single line to ground fault (SLG) or three-phase fault on generator, transformer, or generator cleared by main protection b) Loss of a transmission component - transmission line, transformer, generator without a fault c) SLG fault on bus section or breaker with normal clearing d) SLG fault with delayed clearing on generator, transformer, transmission circuit or bus section. For a) and b) above, no loss of demand is allowed. For other events, depending on system design and expected system, the controlled load shedding and planned removal of some generators is allowed. Additionally, cascading outages are not allowed for any of the above events. United Kingdom The NGC specifies the following disturbances for planning the system: A three-phase-to-ground fault cleared by main protection A single phase fault cleared by backup protection Single phase auto-reclosing of lines Tripping of lines or transformer without a fault 9 Formerly the Western System Coordinating Council. Represents at least 40 electricity providers on the Western seaboard of North America from Canada to northern Mexico. Page 16 Rev /04/04

20 CIGRE CIGRE published a report in 1992 on a survey carried out on standards used in transmission planning. Of the 24 countries participating, 20 (83%) confirmed use of 3-phase faults to test stability. Other findings included: Australia, Brazil and CIS (formerly part of USSR) countries do not plan for 3- phase faults. Australia and CIS use two-phase-to-ground faults and Brazil uses single phase faults. Some countries consider two-phase faults and single phase faults to assess the effect of torsional interaction and voltage transients to generators and industrial users. Page 17 Rev /04/04

21 Appendix D: Damping Criteria for Dynamic Stability The following table compares the criteria across a number of electricity utilities: Utility Damping Criteria Transgrid, VENCorp, Electranet, Western Power Halving time of the least damped oscillations must not be more than 5 seconds. (Australia) Powerlink Damping ratio of at least 0.05 Elsam (Denmark) Oscillations to be damped within seconds Statnet (Norway) Oscillations to be damped within seconds ESB (Ireland) Damping coefficient of not less than 0.05 UK Power frequency oscillations time constant should be less than 12 seconds WECC, (USA) Do not include specific requirement. It is updated from time to time. Page 18 Rev /04/04