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TRANSMISSION PLANNING CRITERIA PREPARED BY: PETER ANG SYSTEM PLANNING BRANCH APPROVED BY: BILL BIGNELL TRANSMISSION DIVISION REPORT NO. TDWP 78-97 January 2006 Printed: 28/02/2008

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Page 1: Network Planing Criteria

TRANSMISSION PLANNING CRITERIA

PREPARED BY: PETER ANG SYSTEM PLANNING BRANCH

APPROVED BY: BILL BIGNELL TRANSMISSION DIVISION

REPORT NO. TDWP 78-97

January 2006

Printed: 28/02/2008

Page 2: Network Planing Criteria

NETWORK PLANNING CRITERIA

DMS#: 1195855 Printed: 28/02/2008 Page 2/60 File#: SDV/77/PC1(156)V1

TABLE OF CONTENTS

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�� �� ���", #-#.�#/��"#��"#� ����������������������������������������������������������������������������������������������������� ��� ����������� ��������� ��������������������������������������������������������������������������������������������������������

����� ���%��-� ����/�#0����-�"��#-1 ��#, #�. ������������������������������������������������������������������������������ 3.3.1.1 Transmission Lines ..............................................................................................................13 3.3.1.2 Power Transformers.............................................................................................................13 3.3.1.3 Loads.....................................................................................................................................13 3.3.1.4 Capacitor and Reactor Banks..............................................................................................13 3.3.1.5 Synchronous Generators .....................................................................................................13 3.3.1.6 Static VAr Compensators (SVCs) .......................................................................................13

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Page 3: Network Planing Criteria

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5.2.1.1 Transformers operating in parallel.......................................................................................36 5.2.1.2 Transformers not operating in parallel ................................................................................37 5.2.1.3 Usable Firm Capacity...........................................................................................................37

�� � �< ��#.=��"#��"#2- ������������������������������������������������������������������������������������������������������������+ 5.2.2.1 1% Risk Factor “m” Factor ..................................................................................................38 5.2.2.2 Applicable Substations.........................................................................................................39 5.2.2.3 Load Shedding .....................................................................................................................40 5.2.2.4 System Spare Transformer..................................................................................................40

�� �� �����"#��"#2- ����������������������������������������������������������������������������������������������������������������'* 5.2.3.1 Applicable Substations.........................................................................................................41 5.2.3.2 Unbalanced Transformer Loadings .....................................................................................41 5.2.3.3 Rating of RRST ....................................................................................................................42 5.2.3.4 NCR Capacity .......................................................................................................................42 5.2.3.5 Substations with Dissimilarly Rated Transformers .............................................................42 5.2.3.6 NCR Capacity < Firm or 1% Risk Capacity ........................................................................43 5.2.3.7 Installation of System Spare Transformer Following Deployment of RRST .....................43

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LIST OF FIGURES Figure 1: Transmission Planning Criteria Overview .................................................................... 7 Figure 2. Highest Acceptable Level and Duration of AC Temporary Overvoltage. .................... 25 Figure 3. Off Frequency Limits for a Typical Steam Turbine. .................................................... 28 Figure 4. Voltage Performance Parameters.............................................................................. 31 Figure 5. Portion of Load Duration Curve ................................................................................. 38 Figure 6. Short and Long Term Boundaries of the CBD............................................................ 46

LIST OF TABLES Table 1. Transmission Elements Qualified as Single Contingency (N-1 Criterion) .................... 21 Table 2. Combinations of Transmission Elements Comprising a Double Contingency (N-2

Criterion) .................................................................................................................. 21 Table 3. Step - Change Voltage Limits ..................................................................................... 23 Table 4. UFLS Scheme Settings (South West Interconnected System).................................... 29 Table 5. UFLS Scheme Settings (North West Interconnected System) .................................... 29 Table 6. CBD Circuit Outage Criteria (Applies to HV Plant Only).............................................. 45 Table 7. CBD Switchgear Outage Criteria (Applies to HV plant only)........................................ 45 Table 8. CBD Major Failure Criteria.......................................................................................... 47 Table 9 Exceptions to the N-1 Criterion - Major Zone Substations............................................ 48 Table 10. Exceptions to the N-1 Criterion - Minor Zone Substations......................................... 49

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PART A – TRANSMISSION PLANNING CRITERIA

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The addition or alteration to the power system of:

• transmission lines

• transformers

• generation or

• load

will impact on the performance of the system.

Western Power Corporation (WPC) is the custodian of Western Australia’s power system and a guardian of system stability, security, reliability and quality of supply for all system users/customers. Although the planning criteria may not be applicable to privately funded loads or generators it will be used to assess whether or not they effect the stability, security, reliability and quality of supply for other users. The “Electricity Transmission Access – Technical Code”, hereinafter referred to as “Technical Code”, and planning criteria documents are intended to prevent detrimental impacts on other system users that may occur due to additions and changes to the power system. The technical requirements for the system are based on the following documents:

• Technical Code

• Transmission Planning Criteria

• Quality of Electricity Supply

• Australian Standards

This document presents the planning criteria used by WPC to ensure that WPC's transmission systems:

• provide acceptable quality of electricity supply

• provide an acceptably reliable electricity supply

• provide adequate security of electricity supply

• maintain safety standards

• satisfy environmental standards

• are developed at the lowest cost possible whilst meeting the constraints imposed by all of the above.

The transmission planning criteria in this document may not be applicable to privately funded interconnections to customer loads or generation provided that the system stability, security, reliability and quality of supply to other users are not effected.

The limits that are applied to loads of individual users with regards to quality of supply are dealt with in the Technical Code issued by WPC.

The concept of transmission system planning and the rationale behind the planning criteria are discussed in Section 2 of this document.

The guidelines for transmission system planning, of particular use to planning engineers, are given in Section 3 of this document. Section 3 outlines the range of technical and environmental considerations to which the planning criteria relate.

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The information provided in Sections 2 and 3 form the basis on which planning criteria and limits are developed in Section 4.

The technical limits that are applied to customers with regards to private interconnection of generation or load are dealt with in the Technical Code and Sections 3 & 4 of this document.

The role of planning criteria are to help strike a balance between customers' desire for a secure, reliable, high quality electricity supply and the desire for this service to be provided at the lowest cost. At the same time, environmental and safety restrictions must be taken into account. Different types of customers have different expectations with respect to their electricity supply. In defining this balance, the requirements of the customer and the potential impact of the planning criteria on these requirements need to be considered.

Where judged necessary, recommendations may be qualified by risk/benefit analysis and other considerations such as capital investment priorities, social needs, the environment and land use constraints. In some cases this may mean a more ‘lenient’ technical solution is permitted, while in other cases a stringent performance criterion may be applied. WPC has an obligation to meet the technical requirements for the transmission system as legislated in the Technical Code.

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It is the responsibility of WPC to ensure that the WPC transmission facilities will provide:

• a safe system

• adequate supply reliability

• adequate security of supply

• adequate quality of supply

Whilst meeting these technical constraints, financial efficiency is pursued by adopting least-cost system expansion planning. Furthermore, transmission planning must take into account physical, social and environmental constraints.

An appropriate balance must be achieved between the opposing goals of providing a technically adequate transmission system whilst minimising costs (to help keep charges “low”). WPC is to endeavour to make a profit, consistent with maximising its long-term value.

The transmission planning criteria are designed to provide a balance between these opposing goals. The planning criteria are used to establish the adequacy of forecasted system performance (with changing load growth and load characteristics) and to determine the need for and timing of system augmentation or re-configuration. System augmentation plans are then developed which will satisfy the planning criteria and environmental constraints.

Figure 1 illustrates The Various Aspects Of The Transmission Planning Criteria.

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WPC’s Corporate Safety Policy states that:

‘Safety is the priority value for all aspects of WPC’s business. WPC facilities will be constructed, maintained and operated to ensure public safety.’

WPC's motivation in promoting safety as a priority is to achieve a safe environment for employees and the public.

New projects, additions, or changes to an existing installation should be planned, designed, constructed, maintained and operated to ensure safety.

The major issues addressed by WPC’s Safety Policy that are relevant to transmission planning are discussed in Section 3.

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The contingency criteria or outage criteria perform two roles:

• they establish the outage conditions for which system performance is examined in relation to the other planning criteria

• they determine the amount of load that may be shed and the restoration times required for particular outage conditions.

The contingency criteria, in combination with the reliability criteria, set the reliability performance level at which the system must adhere to.

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The reliability of a transmission system relates to its ability to continue to supply customers given the finite probability of outages (either planned or forced) of one or more items of plant that make up the system. In combination with the contingency criteria, the reliability criteria effectively set the reliability level at which the system (or ‘sub-divisions’ of the system) performance is planned to match.

This aspect of transmission system planning requires detailed study of the steady state and dynamic state interaction of the generation and transmissions ‘sub-systems’.

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The steady state criteria apply to the normal continuous behaviour of a power system and cover post disturbance behaviour once the system has settled.

Satisfying the steady state criteria involves providing sufficient capacity in the system, at whatever voltage level, to overcome specified contingencies. If insufficient capacity or ‘adequacy’ is provided, then the various protective measures on WPC's or customers' plant may react - leading to varying degrees of loss of supply.

As illustrated in Figure 1, the steady state planning criteria are designed to ensure that there is an acceptably high probability that:

• voltage levels will be within acceptable maximum and minimum limits

• system frequency will be within acceptable maximum and minimum limits

• voltage fluctuations will be maintained within acceptable limits

• appropriate plant ratings or capacity will not be exceeded.

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These limits are discussed in detail in Section 3. When these limits are forecast to be violated, some form of action is taken – either system augmentation works (discussed in Section 2.6) or load management measures (see Section 2.7)

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Stability criteria apply during and immediately after a disturbance before equilibrium conditions are achieved.

The stability criteria outlined in Figure 1 relate more directly to the security of the system. The planning criteria are designed to ensure that with an acceptably high probability the system remains stable following system disturbances that may result in transmission plant outages.

The following aspects of system stability are covered by these criteria:

• transient stability

• dynamic stability

• voltage stability

• frequency stability

These are discussed in Section 3. When either one of these stability criteria is forecast to be violated, some form of action is taken – either system augmentation works (discussed in Section 2.6), load management measures (see Section 2.7) or control system modifications (see Section 2.8).

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Quality of supply criteria regulate or restrict the ‘contamination levels’ of the voltage and current waveforms in the system. Satisfactory performance of the system according to quality of supply criteria is generally checked when some form of augmentation is proposed and with the advent of large new loads. In the latter case, the criteria are applied to the new customer load to ensure that it will not cause quality of supply problems for existing (and future) customers.

The aspects of supply that are checked are:

• voltage fluctuation

• system frequency

• harmonic voltage and current

• voltage unbalance

• electro-magnetic interference

These factors are discussed in detail in Section 3.

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Statement of WPC’s corporate environmental policy:

‘The management and workforce will minimise adverse environmental effects while providing for the efficient and reliable generation, transmission and distribution of electricity’

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WPC's motivation towards meeting this objective is reinforced by the legislative framework for environmental control in Western Australia established by the Environmental Protection Act (1986).

Under provisions of the Act, any new project or change to an existing installation which may have a significant impact on the environment must be referred to the Environmental Protection Authority (EPA) for assessment. Procedures established under the Act are then followed to gain appropriate environmental approvals.

The major issues addressed by WPC’s Environmental Policy that are relevant to transmission planning are discussed in Section 3.

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The need for system augmentation is assessed by comparing the planning criteria with system performance for:

• safety

• increasing load levels

• changing load demand patterns

• particular load characteristics

• changes to the system configuration

In order to satisfy the performance levels, be they adequacy, security, or quality levels, least cost and effective plans are developed. The extent of the system augmentation works are dependent on:

• load forecasts

• the anticipated maximum demands of the customers

• the anticipated maximum demands of wheeling due to Open Access to transmission systems

• the anticipated revenue return which will be provided

• special conditions of the customer's load (eg. lifetime considerations, whether the load will affect the quality of supply to other customers, security of supply required for various processing works). If augmentation is required, it will usually be customer funded.

In some cases, system augmentation works may also be justified on an economic basis where there are immediate benefits in return for capital invested. Examples include the installation of shunt capacitors and the provision of supply at higher system voltages to reduce system operating losses.

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Rather than incur capital expenditure on system augmentation works in response to imminent violation of a planning criterion, it may be possible to change the load characteristic by applying some form of ’demand management‘.

Several strategies have been identified as options for use by WPC to control peak loads:

• Transfer of load: this involves permanent transfer or providing for temporary (emergency) transfer of a portion of load to one or more adjacent zone substations.

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• Curtailable loads and energy: customers are offered an incentive to curtail demand during times of system peak. WPC has in place several contracts with large customers whereby upon request the customer curtails their load in return for a compensatory payment or a lower tariff.

• Time of use pricing: this strategy relies on modifying tariffs to encourage customers, particularly commercial ones, to restrict their peak demand - nominally by shifting their demand to a time that attracts a much lower tariff.

• Co-generation: this involves the purchase of excess power by WPC from industries that have their own generating plant. Although its primary application is towards deferring new generating plant on the system, it is relevant to transmission planning because it could provide additional capacity on the system in a particular area (deferring the need for transmission reinforcement).

The applicability of one or more of these strategies must be determined on a case by case basis.

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Overcoming stability criteria limits usually involves some form of system augmentation, however control system modification can also be useful.

Exitation automatic voltage regulator (AVR), power system stabiliser (PSS), governor and voltage regulator tuning can increase system damping which, in turn, extends stability limits.

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Detailed economic analyses are usually not required for fully funded customer projects or essential (safety related) projects.

Economic analysis serves four functions in relation to power system planning:

• it indicates the return on proposed capital investment

• it facilitates the selection of the most cost effective option

• it facilitates the prioritization of projects relative to other projects which are all competing for limited resources

• it facilitates the refinement of the planning criteria

Cash flow analysis can provide a realistic estimate of the return on the capital investment. Typically, the net present value, internal rate of return and discounted pay back period are used. These figures are used for two purposes:

• to assess if the project meets specified hurdle rates

• to prioritize projects against other projects, allowing Management to allocate (limited) funds

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In this section, each suite of planning criteria is described. This information provides the background for application of the planning criteria to the WPC’s transmission network, as presented in Section 4.

Every power system should be equipped with appropriate control and protection facilities to withstand and overcome major system disturbances. All additions or changes to the existing system will change the system’s performance and must be subjected to review by system studies against appropriate criteria. Such a review enables the formulation of technical requirements for projects.

Transmission Planning Criteria is a combination of standards applied to maintain system integrity, reliability and quality. The transmission criteria are applied to protect the interest of all system users in terms of security, reliability and quality of supply.

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Safety is a high priority in all planning, design, construction, operation and maintenance activities carried out within the power system.

The safety criteria perform the following roles:

• ensures solutions that minimise risk to the public and the WPC’s employees

• ensures solutions that minimise risk to the power system and other plant

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Two deterministic criteria are used in the transmission planning contingency criteria: the N-1 and N-2 criteria.

The N-1 criterion simply means that the consequences of an outage of any one of the N components that make up the transmission system must be examined.

The N-2 criterion is usually applied only for the most important system elements (such as the largest system generator(s) or transmission grid lines). N-2 means that the consequences of two coincident outages (one planned and one unplanned) of transmission elements, at or below 80% of peak load, are examined.

These criteria are termed ‘deterministic’ because they are based on an examination of a limited number of outage scenarios for which the consequences are examined by computer simulation. It determines whether such N-1 and N-2 contingencies would be acceptable if they were to occur.

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The steady state criteria generally define the adequacy of the power system. This is defined by CIGRE as:

‘The ability to supply the aggregate electric power and energy requirements of the customers within the component ratings and voltage limits, taking account of planned and unplanned outages of system components.’

In the following sub-sections, the various components of the steady state planning criteria are defined and explained. In each case an examination of each aspect of system performance is

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carried out taking into account planned and unplanned outages of system components. The requirements differ between the nominated sub-systems of the transmission network, as defined and discussed in Section 4.

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In planning a network it is necessary to assess the reactive power requirements under light and heavy load to ensure that the reactive demand placed on the generators, be it to absorb or produce reactive power, does not exceed the capability of the generators.

Depending on the voltage regulator setting and type of control relative to the rest of the system, a given generator may supply a disproportionate share of the MVAr load on the system. As a worst case, protection may prevent overloading of the generator by tripping it and could lead to cascade tripping of all the generators off the system. Alternatively, for a reactive power demand shortfall, system voltage will fall until the reactive power demand matches supply. In cases of severe shortfalls of reactive power, the voltage may collapse to very low levels.

Power System studies are therefore undertaken at light system load (to check if there is sufficient reactive power absorbtion capability in the system) and at peak load (to check if there is sufficient reactive supply capability in the system) for a range of outage scenarios.

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When fully loaded, lines absorb reactive power. At light loads the longer lines may produce capacitive VArs known as line charging.

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Transformers always absorb reactive power, whereas cables almost always produce reactive power due to their high capacitance.

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Loads generally demand reactive power. A load at 0.95 power factor lagging implies a reactive power demand of 0.33kVAr per kW of power.

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Capacitor and reactor banks provide static reactive power supply and absorption capability respectively.

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Synchronous generators are the main source and sink of reactive power. The balance of reactive power required to maintain voltages within specified limits throughout the system is generally supplied by the synchronous generators connected to the system. Different generators have different reactive power production and absorption capabilities.

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SVCs can perform a variety of functions in addition to high speed continuous voltage control including phase voltage balancing, damping of power system oscillations and control of load rejection over-voltages. These functions are achieved by production or absorption of reactive power.

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Different voltage limits are specified at different points in the system with the goal of providing residential customers with nominal 240/415 volts with a maximum variation under normal steady state conditions of ±6%. The ±6% factor is established by statutory limits.

Voltage limits are set at levels which ensure that voltage fluctuations at the customer’s supply point are, with a high degree of probability, tolerable by the customers' electrical equipment.

Voltage fluctuations are caused by switching of transmission elements or customer loads. Real power swings between two groups of generation may cause voltage disturbances or oscillations (described as transient voltage dips).

The consequences of large step changes in voltage are:

• perceptible flicker in lighting

• voltage at customers' premises falling outside WPC's adopted limits

• possible voltage instability due to load non-linearity

• mal-operation of some equipment

Four categories of voltage limits are considered:

Steady State Voltage Limits:

Steady State Voltage limits should be maintained during steady state operation of the system.

Temporary Over-voltage Limits:

Temporary over-voltages are power frequency over-voltages resulting from system disturbances such as load rejection or phase-to-earth faults.

Transient Over-voltage Limits:

Transient over-voltages are electromagnetic in nature and are the result of switching operations or lightning strikes.

Transient Voltage Dip (TVD) Limits:

Transient voltage dips (see Figure 4) are the result of real power swings or pole slips of a generation group against the main system generation (synchronous instability). The limits prevent loss of customer load, system voltage collapse and synchronous instability.

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System frequency will fall if there is insufficient total generation to meet total power demand. However, due to the frequency dependency of loads, the reduction in system frequency will also result in a reduction in power demand. If this reduction in total load as a consequence of the reduction in system frequency is insufficient to restore balance between total generation and power demand, then loads must be disconnected and continue to be disconnected until the frequency recovers to an acceptable level.

The consequences of prolonged operation at less than nominal system frequency are: damage to generating plant and malfunction of some frequency dependent equipment and devices. The alternatives to shedding load are long-term unavailability of damaged equipment, costly repairs and restricted supplies to customers.

If turbo-generators experience a sudden decrease in the electrical power required, the turbines will speed up (system frequency increases). This is because the retarding torque on the turbine shaft is suddenly much smaller. The extreme case of complete loss of load on the shaft could lead to

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over-speeding with possible drastic mechanical breakdown. To avoid this, several mechanical safety mechanisms are usually built into the machines.

Mechanisms of effective and efficient load shedding are installed in the transmission system to facilitate the maintenance of nominal system frequency.

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• summer continuous rating

• winter continuous rating

• cyclic rating

The planning criteria enables maximum plant utilisation (to defer system augmentation) while ensuring that items of plant are not exposed to excessive risk of damage, accelerated ageing or tripping (due to protection operation).

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Additions to the existing systems in the form of extra lines, transformers or generation may increase the fault level throughout the system or within some area of the system.

For safety reasons, the fault level throughout the transmission system must not exceed the fault rating of any equipment reduced by a safety margin in that part of the system at any time.

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System stability is the ability of a power system when operating under the worst possible credible system load/generation pattern and the most severe N-1 and N-2 contingencies of transmission plant to maintain system integrity, synchronism, and remain within desired limits when subjected to system disturbances. Various types of instability are considered. Instability due to rotor angle has two main types: dynamic and transient stability. Dynamic instability can occur as a result of small system disturbances. Transient instability, on the other hand, usually occurs as a result of larger more sudden disturbances.

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Transient stability is related to the ability of a power system to maintain/retain system synchronism when subjected to a severe disturbance when operating under the worst credible system load/generation pattern and the most severe N-1 and N-2 contingencies of transmission plant. Disturbances include three phase faults on transmission facilities, loss of generation, loss of a large load or other failure. If the relative rotor angle between one (or a group of) synchronous machines and the rest of the system generation reaches and exceeds 180° without returning, a ‘pole slip’ and loss of synchronism or synchronous instability are deemed to have occurred.

Some of the factors influencing transient stability are:

• the impedance between generation sources (XT); higher impedance makes the link weaker or less stable

• generator reactance (lower reactance reduces the initial rotor angle)

• inertia of the generating unit (higher inertia produces a slower rate of change in rotor angle)

• fault clearance time (faster clearance results in lower rotor angle swings)

Transient stability is usually associated with the effect of large disturbances to the system which need to be removed or cleared in order to prevent system instability or disintegration. Any

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faulted or not faulted plant that could potentially lead to system instability must be disconnected or separated from the healthy system.

A three-phase short-circuit is selected as the basis for establishing transient stability limits. A significant number of all HV line faults are three-phase faults. Combinations of events which have a ’reasonable’ probability of occurring should be considered. An example is a single phase fault together with a stuck breaker or single phase reclosing on lines.

When a fault occurs at the terminals of a synchronous generator the real power output of the machine is greatly reduced as it is supplying a mainly inductive circuit. However, the input power to the generator from the turbine has no time to change during the short period of the fault (governors are relatively slow) and the rotor has a tendency to gain speed to absorb the excess energy. At the same time, generation and loads remote from the fault do not suffer the same low voltages as generation close to the fault. This results in an increase in load demand on the remote generation that is not matched by the input power. The rotors on the remote generators therefore slow down as energy is absorbed to meet the load demand. This effect actually results in the rotor angles of the remote generation moving in the opposite direction to those of the generators near the fault. If the fault persists long enough the rotor angle between machines or between groups of machines will diverge (increase) continuously and synchronism could be lost.

Transient stability is based on the relative rotor angle swing between two synchronous machines. Relative rotor angle swings in excess of 90° may lead to the situation where the rotor angle does not return and the angle increases beyond 180° and ‘pole slip’ or synchronous instability occurs. In general, an initial generator relative rotor swing angle which does not exceed 120° could be considered as stable. Relative rotor angle swings of 120° produce transient voltage dips of approximately 0.25 to 0.30pu (that is the voltage drops to about 0.70 to 0.75pu). An initial relative rotor swing angle which exceeds 120° with subsequent swings of lower magnitude would be considered as marginally stable. Relative rotor angle swings exceeding 120° have usually only a small margin before pole slipping occurs. An initial relative rotor swing angle which is higher than 120° may result in a pole slip or repeated pole slipping.

The 120° maximum relative rotor swing angle limit is only a ‘rule of thumb’ particularly in multi-machine or multi-group system.

Relative rotor angle swings in excess of 120° or transient voltage dips in excess of 25% may result in the following detrimental effects on the system:

• system voltage collapse

• motor load loss on undervoltage

• electrical and mechanical stress on system and users’ plant

• pole slipping (due to low synchronising torque at voltages below 0.75pu)

These impacts on a power system are generally not acceptable and need to be prevented.

Limiting the transient voltage dip (TVD) resulting from real power swings or rotor angle swings will minimise these detrimental impacts on the power system (see Figure 4) One of the major factors affecting transient stability is the fault clearance time (FCT). The critical fault clearance time is the longest time that a fault can be allowed to remain on the system while ensuring that transient instability does not occur. Critical fault clearance times (CFCT) should be established for the various fault types at key locations. Protection must then be installed and set to ensure that the critical fault clearance times are achieved.

Generation connected to remote areas, of the main power system via long transmission interconnections are vulnerable to pole slipping. Generation units vulnerable to pole slipping under abnormal system conditions, (for example a stuck breaker and a multi phase fault) should be provided with pole slip protection. The function of pole slip protection is to remove the unstable

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generator from the system and prevent the disturbance from causing major problems to other users. Pole slip protection only removes the pole slipping generator from the system after the machine has slipped at least one pole. Pole slip protection only attempts to minimise the damage to the machine and other users plant. Pole slipping protection is a relay of last resort and should not be used instead of clearing the fault within the critical fault clearance time.

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Dynamic stability is the ability of a power system when operating under the worst possible system load/generation pattern and the most severe N-1 and N-2 contingencies of major transmission plant to:

• damp transient oscillations,

• return to a steady state condition and,

• retain synchronism.

when subjected to small disturbances. A small disturbance may include the effects of continuously changing system load, switching of lines, and larger disturbances including faults.

A system may not become unstable on the initial rotor swing but may subsequently become unstable due to poor damping of the rotor swings. This is known as dynamic instability. Dynamic stability usually applies to power oscillations between individual generators or groups of generators. If the oscillations are not positively damped they can build up in magnitude until generators lose synchronism with each other.

Voltage oscillations can occur in a power system as a result of system power swings or other system resonance conditions.

Dynamic stability can be improved by using power system stabilisers (PSS) on affected generators. These provide a feedback to the generator excitation control systems to damp out power oscillations. Static VAr compensators (SVC) can be used to achieve a similar effect.

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The term voltage stability is usually applied to heavily loaded systems where an operating point is reached beyond which an increase in load demand cannot be met because beyond this operating point, or voltage stability limit, the voltages collapse.

The stability of an asynchronous load is determined by the voltage across it; if this becomes lower than a critical value, induction motors may become unstable and stall. In a power system it is possible for both synchronous and load instability to occur. The former is more probable.

The possibility of an actual voltage collapse depends upon the nature of the load and the fault clearance time. If the load is stiff (constant power) the voltage collapse is aggravated. If the load is soft, eg. heating, the power falls off rapidly with voltage and the situation is alleviated.

Furthermore, voltage oscillations can arise within a power system as a result of resonance conditions. Resonance effects are generally caused by a series resonance between a capacitance and an inductance element. System resonant frequencies can exist above and below synchronous frequency and a latent resonance can be excited by a variety of system disturbances (large or small). If a resonance is excited following a system disturbance, then oscillations appearing as system voltage amplitude modulations can arise. If the damping mode of the system at the resonant frequency is positive then the oscillation will be absorbed by the system. If, however, the damping is negative, the oscillations will build up and lead to supersynchronous (>50Hz) or subsynchronous (<50Hz) instability. If corrective action (typically in the form of load shedding) is not taken then these forms of oscillations can lead to damage of system and customer equipment. Locations with low fault level and a weak electrical connection are prone to sub-synchronous oscillations or resonance.

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Voltage collapse and voltage oscillation damping criteria are specified to ensure voltage stability is maintained. Customers or independent generators who may cause subsynchronous resonance/oscillations (ie by installing series capacitors) must provide appropriate measures at the planning and design stage to prevent introduction of this problem to the WPC system or other user systems.

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The frequency stability criterion relates to the recovery times for excursions of the system frequency from the steady state limits.

Under-frequency load shedding relays are installed at zone substations to shed load at pre-determined levels following loss of a major generator or its interconnection.

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Quality of supply criteria sets the acceptable limits on the amount of distortion or corruption of the current and nominal voltage waveforms from the pure 50Hz sinusoidal waveform.

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These limits have been discussed in Section 3.3.2.

The limits are listed in Section 4.

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These limits have been discussed in Sections 3.3.3 and 3.4.4. The limits are listed in Section 4.

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Harmonics relate to the distortion of voltage and current waveforms from the ideal supply at constant voltage and constant frequency.

Some of the main sources of harmonics are:

• Switching forms of control based on power thyristors as used in:

� arcing load such as those of arc furnaces

� thyristor-controlled reactive-power compensators

� thyristor-controlled series capacitors

� frequency converter (ie cycloconverter)

� HVDC converter stations

� high-power ac/dc conversion for the supply of loads such as those of smelters

� thyristor-controlled motor load

� other industrial and domestic loads including thyristors.

• harmonics in the magnetising current of transformers, particularly the third harmonic, due to the non-linear form of transformer magnetisation characteristics

• waveform distortion in rotating machines in transient periods immediately subsequent to disturbances to steady operating conditions

• variations in air-gap reluctance which set up a continuous variation in flux which in turn distorts wave shapes

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• flux distortion in synchronous machines arising from pulsations and oscillations in the field flux caused in turn by movement of the poles in front of the projecting armature teeth

The adverse effects of harmonics in power systems can be widespread:

• Thermal stressing in rotating machines and transformers

• Overloading of shunt capacitor banks

• Interference with:

� power line carrier communications systems

� public telecommunication facilities

� protection functions

� the firing sequence in thyristor controllers

• possible resonances at harmonic frequencies

• errors in metering and instrumentation

• malfunction of computer equipment

• rotating machine vibration

The total and contribution limits imposed by WPC are listed in Section 4.5. Individual non-integer (fractional) harmonics should be included in the distortion limits by incorporation into the nearest even harmonic limit.

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When power and telephone lines run in parallel, voltages sufficient to cause high noise levels may be induced into communications circuits under certain conditions.

The major problem, however, is due to ground faults producing large zero-sequence currents in the power line which induce voltage into the neighbouring circuit.

The limits are based on the requirements of Australian Standards.

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An internationally accepted standard for voltage unbalance is the ratio of applied negative sequence voltage to positive sequence voltage should be less than 1%. This level can be acceptable for induction motors.

Voltage unbalance in the transmission system due to asymmetry of transmission lines is reduced in WPC's systems by line transposition.

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Figure 1 illustrates the various aspects of transmission planning criteria. In this section, the planning criteria applicable to the WPC’s transmission networks of the South West Interconnected System (SWIS) and to the North West Interconnected System (NWIS) are presented.

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Appropriate system performance will be maintained by meeting the technical requirements contained in the Technical Code and the Transmission Planning Criteria.

Adequate System Performance will be ensured by fulfilling the following criteria:

• contingency

• reliability

• steady state

• quality of supply

• stability

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The transmission system, that interconnects generation and terminal stations, consists mainly of transmission lines, transformers, busbars, switchgear and other circuit components. Terminal stations are included in the transmission grid.

Loss or outage of a transmission system major component like a breaker, busbar, line, transformer, or generator, etc. usually affects the transfer capacity. The main purpose of the contingency criteria is to ensure the adequacy of the system.

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N-1 criterion:

The system must be capable of withstanding the loss of any single component at any load level and for any generation schedule.

Notes:

1. The system is generally examined under normal generating schedules with the machine which has the largest impact on the contingency being examined out-of-service

2. The single component referred to in the above criteria include those listed in Table 1 below.

The N-1 contingency criterion applies to:

• all aspects of the steady-state criteria

• all aspects of the stability criteria

• all aspects of the quality of supply criteria

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N-1 Outages

Transmission Line

Transformer

Static VAr Compensators

Busbar

Circuit Breaker

N-2 Criterion:

The system must be capable of withstanding one unplanned outage coincident with one planned outage of transmission elements in the combinations listed in

Table 2 at up to 80% of peak system load.

In relation to the N-2 criteria, it is to be assumed that during the planned outage generation has been rescheduled to mitigate the effect of a subsequent outage.

The N-2 contingency criterion applies to:

♦ all aspects of the steady-state reliability criteria

♦ all aspects of the stability reliability criteria

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N-2 Outages

Transmission line and transmission line

Transformer and transformer

Transformer and transmission line

Busbar maintenance and transmission line

Busbar maintenance and transformer

Circuit breaker maintenance and transmission line

Circuit breaker maintenance and transformer

Circuit breaker maintenance and busbar loss

Stuck Breaker Criterion:

For those cases where stuck breaker protection, initiated by line or transformer faults, results in the tripping of additional lines or transformers, the bulk transmission system must satisfy steady state criteria at 80% of peak load without generation re-scheduling.

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N-1 criterion:

The system should be capable of restoring 100% of supply following the loss of any single component of the interconnectors between the Port Hedland, Karratha, and Dampier areas at any load level within 30 minutes. The ties within an area should meet the SWIS’s N-1 criterion.

Notes:

1. the 30 minute time period is designated to provide time for standby generation to be fully loaded following the loss of power transfer across the CLB-HDT 220kV interconnection for the case where the Port Hedland load is supplied from CLB Terminal

2. the single component could be, for example, a busbar, a transformer, a capacitor bank or a transmission line.

The N-1 contingency criterion applies to:

• all aspects of the steady-state criteria

• all aspects of the stability criteria

• all aspects of the quality of supply criteria

The other criteria applied in the NWIS are the same as the SWIS.

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Each of the steady state criteria should be satisfied for the contingency criteria in Section 4.2.1 (N-1 and N-2 criteria):

Voltage Limits:

Steady State Voltage Limits:

The continuous system voltage should not exceed the design limit of 110% of nominal voltage and should not fall below 90% of nominal voltage.

Step changes in voltage should not exceed the limits specified in

Table 3.

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Cause of Outage Pre-Tap Changing Post-Tap Changing (final steady state volts)

HV Voltage

MV Voltage HV Voltage MV Voltage

Routine Switching Step change

±3.7% (max)

±3.7% (max)

Transmission voltages should be between 110% and 90% of nominal voltage

Should attain previous set point

Infrequent Switching & faults

+6%,-10% (max)

+6%,-10% (max) ±10% (max) Should Attain previous

set point Notes:

1. Specification of transformer tap changing range is critical in meeting the limits in Table 3 and the statutory ± 6% customer voltage supply limit.

2. Series reactors should be used in the circuits of all shunt capacitor installations to limit the effects of inrush current.

Thermal limits:

The following thermal ratings should not be exceeded under normal or emergency operating conditions:

• Transformers:normal cyclic rating

• Switchgear:TRIS summer and winter rating

• Lines:TRIS summer and winter rating

Note: TRIS - Transmission Ratings Information System

Fault limits:

The fault level is limited to 95% of the equipment fault rating throughout all the WPC’s Transmission Grids.

Generating limits:

Limits to the VAr generation and absorption capability of thermal plant, gas turbines and reactive compensation plant such as static VArs compensators should not be exceeded.

Note: Generator capability diagrams should be consulted when reviewing the reactive capability of the machines to generate and absorb reactive power. Generator capabilities should be checked with machine owners to ensure that no other factors limit machine MVAr generation.

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Generation scheduling:

Under steady state operating conditions, the SWIS Transmission Grid system should not restrict economic scheduling of generation amongst power stations except for N-2 outages.

However, with a pre-existing single outage, economic scheduling of generation may be restricted due to the need to reschedule generation in preparation for a second unplanned outage.

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Frequency Limits:

Under normal conditions the system frequency should be maintained at 50Hz ± 0.2 Hz.

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Each of the steady state criteria should be satisfied for the N-1 criterion (Section 4.2.2):

Frequency Limits:

Under normal conditions the system frequency should be maintained at 50Hz ± 0.5 Hz.

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System conditions:

Each of the stability criteria should be satisfied under the worst possible system load/generation pattern and the most severe N-1 or N-2 contingencies of major transmission plant as specified in Section 4.2.

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Temporary Over-Voltages:

Temporary AC over-voltages should not exceed the time duration limits given in Figure 2.

There necessary to ensure that the temporary over-voltages are limited to the withstand levels following measures could be applied:

Capacitor switching schemes

Reactor switching in schemes

Static Var Compensation

Other o/voltage protection schemes or measures

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Transient Over-Voltages:

Surge arresters should be used where necessary to ensure that the transient over-voltage seen by an item of transmission plant is limited to its impulse withstand level.

Transient voltage dip criteria (TVD):

After clearing a system fault the voltage should not drop below 75% and shall not be below 80% for more than 0.4 seconds during the power swing that follows the fault". The maximum transient voltage dip is 25% and the maximum duration of voltage dip exceeding 20% is 20 cycles (400ms). (see Figure 4 for more details).

Voltage stability:

Voltage Collapse:

All necessary steps should be taken to ensure that voltage collapse does not occur for the most onerous outage of a transmission element under credible generation schedules under full load conditions. It should also be assumed that 3% of the installed capacitors are unavailable plus the largest system bank should also be considered as unavailable. Voltage collapse is associated with a deficit of reactive power. Adequate reactive reserves should be provided (see notes below).

Voltage Oscillations:

Adequate damping should be provided to ensure that all oscillations of fundamental and harmonic frequency are well damped as required in Section 4.4.4. Sub-synchronous and super-synchronous oscillations should be damped accordingly within five seconds or otherwise counter-measured by appropriate action within less than two seconds.

Notes:

For Terminal Stations in the Metropolitan Area the following procedure is used;

• Currently, the conditions which may take the system closest to voltage collapse occurs when one Kwinana Stage C generator is unavailable (the generator that provides the greatest MVAr support to the Metropolitan Area) and there is a forced outage of one MU 330kV line at peak system load.

• 3% of the total installed capacitance plus the largest HV capacitor are to be taken out of service. This level of capacitor bank unavailability was determined in 1998 by System Planning Branch and System Operations.

For other areas of the system, including radials, the following procedure is used to determine the voltage stability or transfer limit;

• The line or tripping of a generator that causes the largest reduction in system voltage support in the area of interest is taken as the disturbance used to establish the transfer limit or reactive support limit.

• The normal peak system generation pattern that provides the lowest level of voltage support to the area of interest is assumed. (Of these units, normally in service in the area, the largest unit is assumed to be out of service due to a breakdown or other maintenance requirements. If another unit is assigned as a backup unit then it may be brought into service to support the load area.)

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• The largest capacitor, in the area is to be taken as out of service.

In all situations the following procedures are followed;

• All loads are modelled as constant P & Q loads.

• The load to be used in the study is to be taken as 10% higher than the expected system peak. The system peak load is determined by linear extrapolation of the system’s historic peak load, with an allowance for block loads. (The 10% margin includes a safety margin for hot weather, data uncertainty and uncertainty in the simulation.)

• A positive MVAr reserve margin is to be maintained at major load points for this 10% higher load. (System voltages should remain with the normal range).

• All other generation is to be taken as available with none of the steady state MVAr limits to be exceeded.

• System conditions are checked after the outage but prior to tap changing of transformers.

• Total system load in the area of interest is not to be overcompensated. (The installed capacitor banks capacity is not to exceed the MVAr draw of the load at peak load).

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Operation at off-nominal frequency causes an accumulation of stress in turbines. These need to be limited in frequency excursion and restricted in time duration of the frequency excursion. The capability of a typical steam turbine, (usually the most restricted unit for stress accumulation) to withstand operation at off-nominal frequencies is shown in Figure 3.

Frequency stability:

Following loss of generating plant, system frequency shall recover to a steady state value within frequency and time limits as specified in the Technical Code. Restoration of frequency to within steady state limits is then accomplished by operator action and automatic govenor control (AGC), if it is operating.

To cover for a loss of generating plant two measures are applied to arrest the falling frequency following the loss of generation and to return the frequency to within normal operating levels:

• spinning reserve (the use of fast response plant)

• under-frequency load shedding (UFLS)

Spinning Reserve Policy:

System Operations will schedule the level of spinning reserve to cover for the loss of the biggest generation unit to avoid UFLS operation taking into account the interruptible loads.

UFLS Criteria:

UFLS are designed to restore system frequency to normal operating levels for a loss of up to 75% of the system generation.

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The present settings1 for the South West Interconnected System under-frequency load shedding scheme are given in Table 4 and for the North West Interconnected System under-frequency load shedding scheme are given in Table 5.

Note, that switchable capacitor banks at substations should also be shed in accordance with Table 4 and Table 5.

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Stage Frequency (Hz)

Time Delay (s)

Load Shed (%)

Cumulative Load Shed (%)

Capacitor shed (%)

Cumulative Capacitor Shed (%)

1 48.75 0.4 10 14 10 10

2 48.50 0.4 14 24 14 24

3 48.25 0.4 15 39 15 39

4 48.00 0.4 12 51 12 51

5 47.75 0.4 12 63 24 75

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Stage Freq. (Hz) Time Delay (s)

Load Shed (%)

Capacitor Shed (%)

1 49.00 0.5 16 35

2 48.75 0.5 16

3 48.50 0.5 17

4 48.25 0.5 14

5 48.00 0.5 15 18

Not Shed 22 47

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Faults:

The most severe of the following fault types should be selected as the type of fault to determine the stability of the power system with due regard to reclosing;

• A three-phase-to ground fault,

• A single-phase to ground fault cleared by backup protection

• Single Phase Auto Reclosing of lines or,

• Tripping of line or transformer without a fault.

Transient stability:

Transient stability must be maintained for faults cleared by tripping of any transmission element or a generator under the worst possible system

1 The settings presented in Tables 4 & 5 are subject to change as the SWIS and NWIS changes.

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load or generation pattern. The relative rotor angle swing between two or more groups of generators on the network should not exceed 180 degrees after allowing for a safety margin. Due consideration must be given to the Transient Voltage Dips Limits to prevent motor loads being disconnected from the system by the undervoltage resulting from the transient power swings.

Transient stability is usually associated with a dramatic disturbance to the system which needs to be removed/cleared in order to prevent system instability or disintegration. Any faulted or not faulted plant leading to system instability under the worst possible system load/generation pattern and the most severe N-1 and N-2 contingencies must be removed or separated from the healthy system.

Out of Step Protection

Generation units vulnerable to pole slipping under abnormal system conditions, (for example a stuck breaker and a multi phase fault) shall be provided with pole slip protection. The function of pole slip protection is to remove the unstable machine (usually generator or synchronous compensator) from the system and prevent the disturbance from causing problems to other users. Pole slip protection only removes the pole slipping unit from the system after the machine has slipped at least one pole. Pole slip protection only attempts to minimise the damage to the machine and other users plant. Pole slipping protection is a relay of last resort and should not be used instead of clearing the fault within the critical fault clearance time.

The critical fault clearance time at a point in the network should be greater than the “total fault clearing time” plus a margin of 20ms. The total fault clearing time is defined as the total breaking time of the circuit breaker plus the maximum operate time for the protection for a bolted close in fault.

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Oscillation damping:

All electromechanical oscillations of real power or sub-synchronous oscillations resulting from any small or large disturbance, and under the worst possible system load/generation pattern and the most severe N-1 and N-2 contingencies of major transmission plant should be well damped and the system should return to a stable operating condition.

The damping ratio of the oscillations should be at least 0.5. For inter-area oscillation modes, lower damping ratios may be acceptable but the amplitude halving time of such electromechanical oscillations should not exceed five seconds.

Sub-synchronous and super-synchronous oscillations should be damped accordingly within five seconds or otherwise should be counter-measured by appropriate action to remove them.

The Power System Stabiliser settings shall be optimised to provide maximum damping.

If power system simulation studies indicate the possibility of insufficient damping then a Generator must provide power system stabilising facilities on each synchronous generating unit even if the unit sizes are smaller than 30MW, if other system users may be effected.

Users/customers or generators who may cause subsynchronous resonance oscillations must provide appropriate measures at the planning and design stage to prevent introduction of this problem to the WPC or other user systems.

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The limits applicable to the transmission network are included in the Technical Code.

Harmonic Contribution Limits:

The harmonic voltage distortion produced by the customer’s plant shall not exceed 30% of the limit values (individually and total) given in the Technical Code – Tables 2.1 to 2.3.

Existing (background) levels of harmonic voltage distortion are not included when assessing the harmonic contribution.

Non-integer (fractional) harmonics should be included in these limits:

Each non-integer harmonic should not exceed the limit specified in the Technical Code, for the nearest even integer-harmonic. Total harmonic voltage distortion including these non-integer harmonic contributions should not exceed the limit specified in the Technical Code for total harmonic voltage distortion.

The energy contained in each non-integer and integer harmonics should be included in the total harmonic limits (This is essential to minimise the risk to plant).

More detail is provided in the Technical Code.

Notes:

1. Intermittent (transient) harmonic voltage distortion is subject to the same limits as continuous harmonic voltage distortion and should be included in assessing thermal ratings.

2. Inter-harmonics (Non-integer or fractional) harmonics are subject to the same limits. They should be treated as an even integer (the nearest order) harmonic.

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As part of the planning process the safety risk should be considered for any new developments and the existing facilities which may have a significant impact on the safety:

Safety and Prevention

Assess the safety risk in the planning process. Inform, consult and rectify existing or foreseeable safety risks with relevant bodies in order to ensure safety is maintained to Industry Standards.

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As part of the planning process the following criteria should be administered for any new developments and facilities which may have a significant impact on the environment:

Social Issues

Inform and consult with relevant public bodies, community interest groups and the general public.

Electromagnetic Fields

Assist in maintaining electromagnetic field exposure to the public and Western Power employees at levels within industry standards.

Land-use Considerations

Avoid where economically possible the use of land where conflicting uses or potential uses exist.

Noise

Meet and, where possible, better the noise limit provisions of the Environmental Protection Act.

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PART B – SUBSTATIONS PLANNING CRITERIA

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This section describes the criteria used to determine the timing and extent of substation reinforcements and the reliability in Western Power’s sub-transmission substations. Presently, there are three reliability criteria for determining the supply capability of a zone substation. These are,

1. N-1 Criterion: which defines the Firm Capacity.

2. 1% Risk Criterion: which defines the 1% Risk Capacity.

3. NCR Criterion: which defines the NCR Capacity.

Generally, but not necessarily2, the following rule holds,

NCR Capacity > 1% Risk Capacity > Firm Capacity.

The total capacity of a substation can be limited by any one or more plant items comprising the following main components in a substation:

• Transmission line circuits.

• Power transformer circuits.

The adequacy of transmission line circuits supplying sub-transmission substations are assessed through load flow studies subject to the N-1 criterion. On the other hand, the adequacy of power transformer circuits are assessed by comparing the forecasted substation peak load with the substation’s capacity determined using the N-1, 1% Risk or NCR reliability criterion depending on the type of substation under consideration.

Subject to the reliability criteria, the amount of load that can be supplied is limited by primary plant equipment ratings and, exclusively in the case of the N-1 criterion, the amount of distribution transfer capacity (DTC) available.

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Typically a power transformer circuit will consist of one major item of equipment, i.e., the power transformer and minor items of equipment including current transformers, cables, conductors, connectors and circuit breakers.

Transformer loading over the course of a day tends to be cyclic and transformers have high thermal inertia. As a result, Western Power assigns one of three different thermal ratings depending on the daily load and temperature profile of the load area supplied by a substation.

• Name Plate Rating (NPR): Continuous rating guaranteed by manufacturer.

• Normal Cyclic Rating (NCR): Maximum calculated load that the transformer can supply, in accordance with IEC 354, without causing accelerated ageing. It takes into account the maximum

2 Mainly due to transformer unbalanced loading as will be discussed in section 5.2.

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allowable transformer hot spot temperature, and the cyclic variation in the daily load profile and daily temperature profile.

• Long Term Emergency Rating (LTER):

Maximum calculated load the transformer can supply, in accordance with IEC 354, for peak summer temperature and peak load curves without the maximum allowable winding hot spot temperature being exceeded3. The maximum hot spot temperature is typically 1300C and 1400C for older and newer transformers respectively.

Transformer internal components including HV & LV leads, bushings, winding temperature indicator (WTI) current transformer (CT) and line drop compensator (LDC) CT are assigned ratings specific to each component, which may be less than the transformer NCR or LTER ratings. This is referred to as the component limiting rating (CLR) of the transformer.

Minor components in the power transformer circuit generally have short thermal time constants, i.e., low thermal inertia. The ratings of these components are not affected by variations in daily load and temperature profiles. These components can also limit the rating of the power transformer circuit below the transformer’s NCR or LTER ratings.

The following points apply when determining the rating of a transformer circuit:

• The transformer circuit rating to be used in determining the capacity of a substation is that of the lowest rated component in the entire power transformer circuit.

• The highest rating that is allowed by Western Power to be used in determining the transformer circuit rating is the transformer NCR4 rating.

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Distribution Transfer Capacity (DTC) refers to the amount of load that can be transferred to adjacent substations via interconnected distribution networks by switching normally open points in the distribution system. DTC is typically effected over a period of several hours. The amount of DTC available at a substation depends on:

• Available spare capacity on individual feeders interconnecting adjacent substations.

• Available spare capacity at adjacent substations.

• Ability to maintain the distribution network voltage profile within regulatory limits.

Due care must be exercised when including DTC in determining substation capacity for the following reasons:

• Distribution network re-configurations and variations in feeder loading directly impact the amount of DTC available. Increasing or reducing DTC depending on the nature of change. As a consequence, available DTC at each substation must be reviewed regularly.

• Determination of DTC at a substation is based solely on distribution network parameters and limitations. It does not take into account the capacity of adjacent interconnected substations, which may restrict load transfer.

3 When the load demand curve is “peaky”, the NCR may be almost as large as the LTER. 4 Transformer NCR and LTER rating calculations carried out on a sample group of substations suggest

that generally LTER rating is similar to the NCR rating.

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Historically, transmission system reinforcement or augmentation planning has been carried out using a deterministic approach, i.e. using the N-1 or N-2 criteria as defined in clause 2.7.

Applying such deterministic planning approaches achieve a high degree of reliability in the transmission system, however this invariably results in a high degree of redundancy in primary plant. The costs associated with maintaining such a high level of redundancy in the transmission system is high.

Since 1998, Western Power’s planning approach for substations in the Perth metropolitan area has evolved towards a combined deterministic/probabilistic planning approach on which the 1% Risk and NCR criteria are based. This new approach manages the risk and duration of supply interruptions to customers under N-1 contingency conditions thereby allowing greater utilisation of available capacity. Applying a combined deterministic/probabilistic approach inherently introduces higher risk, however the economic benefits accruing from allowing higher loss of load risk are considered to outweigh the costs.

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The N-1 Criterion is used to define a substation’s firm capacity (FC) and is calculated as follows:

• One transformer substation: FC = DTC...................................................... (1)

• Two transformer substation: FC = NCR1 + DTC......................................... (2)

• Three Transformer substation: FC = NCR1 + NCR2 + DTC ............................ (3)

Where, NCR1 = lowest NCR of the transformers in the substation;

NCR2 = second lowest NCR of the transformers in the substation;

DTC = available distribution transfer capacity. As defined in section 5.1.2, DTC shall be included in eqns (1), (2) and (3) above only if there is a high degree of confidence in its accuracy.

Inclusion of DTC in the firm capacity of a substation introduces the possibility of overloading on remaining transformer circuits following the outage of one transformer circuit. Two overload scenarios can arise depending on the substation’s mode of operation.

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In the Perth metropolitan area, Western Power zone substations are not generally operated with transformers in parallel under normal operating conditions due to fault rating limitations on distribution network equipment. The scenario below applies when temporary short-term paralleling is necessary.

Following the outage of one transformer circuit, the full substation load will immediately be applied to the remaining transformer circuit(s). If the substation is loaded to its firm capacity which includes DTC prior to the outage, then the remaining transformer circuit(s) will be loaded beyond its thermal limit until either consumer demand and/or ambient temperature decreases or until DTC is effected. Normally, switching to effect DTC can be carried out within a maximum of 2 hours.

The risk of plant overloading must be managed to ensure the safety of plant and personnel.

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In this case load connected to the faulted transformer will be tripped immediately – the remaining transformer(s) is not subjected to any more load than it already supplies until the tripped feeders are restored.

The procedure used by Western Power for restoring lost load is for operators to reconnect feeders one at a time while monitoring the load on the remaining transformer(s) as this is being done, ensuring acceptable loading levels on the transformer(s). If the load exceeds capacity then distribution transfer capacity must be utilised, with remaining feeders not being reconnected until distribution transfer is complete.

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A substation’s firm capacity calculated from equations (1), (2) or (3) is an ideal capacity that may not be fully utilisable in practice for the following reasons:

• At substations with three transformers not operating in parallel, it may not be possible to achieve balanced loading on the two remaining in-service transformers following an N-1 transformer outage. Balanced loading is implicitly assumed as part of the firm capacity derivation. The following factors restrict the ability to achieve even loading of transformers.

� The need to keep transformers split on the LV to limit fault levels.

� Feeder loads are discrete and vary in size.

� Numbers of feeders on bus sections are not necessarily the same.

� Seasonal variation in feeder loads.

� Variations in daily feeder load profile.

� Feeder(s) with distribution transfer capacity may be aggregated on one bus section.

� There may not be adequate operational personnel to carry out distribution network re-configuration to optimise distribution transfer capacity.

� Bus-sections may or may not have capacitor banks.

Unbalanced transformer loading is of particular concern at three transformer substations because as a result of the above points, load previously supplied by the faulted transformer circuit cannot be distributed appropriately to the remaining transformer circuits. This may result in overloading of either one of the remaining two transformer circuits. Increasing the flexibility of the LV busbars can alleviate this problem, i.e. allowing more transferability of feeder circuits between transformer circuits. Western Power’s standard substation configuration is shown in Appendix B.

• Transformer NCR ratings are calculated based on the worst-case daily load profile and allowing the hot-spot temperature to reach 1400C (1300C for older transformer designs). Beyond these limits the transformer is vulnerable to system disturbances and could trip due to gassing of oil. In some instances, the calculated NCR rating of transformers may not be available due to faster than expected hot-spot temperature rise.

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The 1% risk criterion is used to define a substation’s 1% Risk Capacity. Under this criteria ideal 1% Risk capacity is calculated as follows:

1% Risk Capacity = FC × (1 + m)............................................ (4)

Where, FC = substation firm capacity as calculated in section 5.2.1.

m = 1% risk factor (refer to section 5.2.2.1).

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Practically5, it is calculated in the following manner:

1% Risk Capacity = FC’ × (1 + m) + DTC...................................... (5)

where, FC’ = substation firm capacity excluding DTC.

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The 1% Risk factor “m” in equations (4) & (5) can be defined as,

‘A substation’s peak load that is demanded for 1% of time in a year or less (ie. ≈≈≈≈ 87 hours) expressed as a proportion of its firm capacity excluding DTC.’

For example, with reference to Figure 5 below, the substation peak load at a substation with FC’ of 22.48MVA is (b) 30.32MVA and the load demand that is exceeded for 1% of time in a year is (a) 29.13MVA. Therefore, in this example,

05.048.22

13.2932.30 =−=m .................................................. (6)

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Studies indicate that typical values for m are between 0.10 and 0.15 depending on the load duration curve for each particular substation. For planning purposes, the generally accepted figure of 0.10 is used regardless of site. Due care in the selection of m must be exercised

5 DTC is excluded from the firm capacity when multiplying by (1+m) to reduce the degree of uncertainty

in the 1% Risk capacity because the availability of DTC cannot be guaranteed for the reasons outlined in section 5.1.2.

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where the substation load consists of a high proportion of non-cyclic type loads. In this case, an examination of the substation’s load duration curve may be necessary to determine m.

Loading a zone substation up to its 1% risk capacity means that in the event of a transformer circuit outage any load above the substation’s firm capacity must be shed in order to prevent overloading of the remaining transformer circuit(s). Applying the 1% risk criterion as per section 5.2.2 implies that with the loss of a single transformer circuit,

‘The proportion of a substation’s peak load that is demanded for 1% of time in a year or less (ie. ≈≈≈≈ 87 hours) is not backed-up.’

It is also important to note that the 1% risk criterion is based on the firm capacity, it therefore inherits all the shortcomings of the N-1 criterion as per section 5.2.1.

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This criterion shall be applied to metropolitan zone substations only and to further minimise the negative impact of supply interruption where load shedding is necessary, the 1% risk criterion shall not be applied to the following,

• Perth central business district (CBD) substations.

• Double LV busbar substations.

• Substations for which a spare transformer is not available.

At substations where the 1% risk criterion is applied, feeders supplying critical or sensitive loads shall be exempt from rotational load shedding.

Based on the 1% risk criterion reinforcement planning must conform to the following requirement:

‘Major reinforcement of an urban zone substation shall not proceed until the peak load demand reaches a level where load demand in excess of the substation capacity must be supplied more than 1% of the year, i.e. 87 hours.’

Before application of the 1% Risk criterion for planning substation capacity reinforcement, the substation firm capacity shall be maximised by ensuring that:

• Capacitor banks are in service during peak periods.

• Distribution transfer capacity is utilised where necessary following a transformer outage.

• Transformer NCR rating is maximised up to an economically justifiable level.

• Transformer circuits are rated to the transformer NCR rating where technically and economically viable.

• Load characteristics are modified, where possible, to reduce peak load demand (demand management) and/or peak loading of transformer circuits (load balancing).

The 1% risk criteria allows greater utilisation of available substation capacity and therefore temporarily defers the need for high capital cost reinforcement projects such as third transformers or new substations.

The use of the 1% risk criteria is being phased out due to the introduction of the NCR criteria (refer to section 5.2.3). It is expected that by 2003 there will not be any Western Power zone substation operating under this criterion.

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The 1% risk criterion introduces a window of risk at a substation where – for a number of years prior to reinforcement – a risk of rotational load shedding exists in the event of a transformer circuit outage. The most onerous case where the highest amount of load is at risk is in the final year prior to reinforcement. Based on a study comparing the maximum shed load at various risk levels with the average substation feeder loading level at a sample number of substations, it was concluded that at the 1% risk level6:

• Probably only one feeder would need to be shed on a rotational basis at any one time because the maximum load shed is, for the substations considered, close to or less than the average feeder load level.

• Load shedding at a substation would probably only need to occur for one period a day until the transformer circuit can be reinstated.

This assumes that the transformer circuit is reinstated within a maximum of 10 days and there is an adequate number of feeders at the substation to minimise the amount of time each feeder must be shed.

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The ability to meet the requirement for re-instating the out-of-service transformer circuit within a maximum of 10 days is critically dependent on the availability of a suitable system spare transformer. This transformer must be available for service any time there is a transformer failure.

Once the system spare(s) has(have) been used, a system spare may not be available until the failed transformer(s) has(have) been repaired. Western Power’s policy is to hold two 132/22-11kV and one 66/22-11-6.6kV cold mobile system spare transformer.

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The NCR criterion is used to determine a substation’s NCR capacity. The Ideal NCR capacity is calculated as follows:

• One-transformer substation : NCR Capacity = NCR1 (7)

• Two-transformer substation : NCR Capacity = NCR1 + NCR2 (8)

• Three-transformer substation : NCR Capacity = NCR1 + NCR2 + NCR3 (9)

Where, NCRi = normal cyclic rating of the ith transformer in the substation.

Important points to note are:

• At substations with more than one transformer, the ideal NCR capacity must be de-rated if there is any uneveness in the loading of non-paralleled transformers. A possible solution to maximise load balance is to operate the transformers in parallel. However, this is not presently feasible at existing substations as distribution network equipment in proximity to substations are not adequately rated to withstand the resultant fault level.

• The NCR capacity cannot incorporate DTC because this may potentially lead to transformer circuit loading beyond the NCR capacity resulting in accelerated ageing of transformers.

• The ideal substation NCR capacity must be further de-rated, if a transformer circuit’s rating is greater than the rating of the RRST (refer to section 5.2.3.3).

6 Different conclusions would apply at higher risk levels, eg. it is likely that more than one feeder would

need to be shed at any one time.

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For the purposes of clarity the following terms are defined:

• Rapid response spare transformer (RRST) – refers to a custom built mobile spare transformer that can be transported to site, installed and commissioned for temporarily replacing a failed transformer within an average of 9 hours of the initial failure.

• Ideal NCR capacity – refers to the substation’s NCR capacity calculated either from eqns. (7), (8) or (9).

• NCR capacity – refers to the substation’s NCR capacity that takes into account transformer unbalanced loading and the RRST rating limit.

Sections 5.2.3.2, 5.2.3.3 and 5.2.3.4 provide further details on the methodology for calculating a substation NCR capacity that incorporates these de-rating factors.

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The NCR criteria may be applied to zone substations that are non-CBD and non-critical (ie. with load that can tolerate supply interruptions of up to an average of 9 hours, in the worst case) and are geographically located such that the RRST (refer to section 5.2.3.3) can be transported and deployed within an average of 9 hours.

A single RRST is capable of covering up to 30 substations and once deployed is designed to re-supply all load lost due to the initial N-1 supply interruption.

Before application of the NCR criterion for planning substation capacity reinforcement, the substation firm capacity should be maximised by ensuring that:

• Capacitor banks are in service during peak periods.

• Distribution transfer capacity is utilised where necessary following a transformer outage.

• Transformer NCR rating is maximised up to an economically justifiable level.

• Transformer circuits are rated to the transformer NCR rating where it is technically and economically viable.

• Load characteristics are modified, where possible, to reduce peak load demand (demand management) and/or peak loading of transformer circuits (load balancing).

The NCR criterion allows greater utilisation of available substation capacity and therefore temporarily defers the need for high capital cost reinforcement projects such as additional transformers or new substations.

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In two or three transformer substations, the ideal NCR capacity must be derated if there is any uneveness in the loading of non-paralleled transformers. In order to simplify the calculation of NCR capacity due to unbalanced transformer loading the following assumption is made,

‘As the substation load grows, the load on each transformer grows in constant proportion with each other until the heaviest loaded transformer is loaded to a limit of 75% of its NCR rating.’

This constant, “u”, is defined as:

Tx

Tx

LR

u×= 75.0

........................................................ (10)

Where, u = ideal NCR capacity reduction factor (refer to section 5.2.3.4).

RTx = rating of the heaviest loaded transformer circuit as per section 5.1.1.

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LTx = load of the heaviest loaded transformer circuit.

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A rapid response spare transformer (RRST) is an integral part of the NCR criterion because it is required to achieve an average transformer circuit restoration time of 9 hours. In the event of a transformer circuit failure, the load previously supplied by the faulted transformer circuit has to be supplied via DTC or shed until the RRST can be deployed as a replacement for the failed transformer. Once the RRST is in-service load subjected to shedding can be restored. Any load above the RRST rating will continue to be shed. Therefore, if the rating of the heaviest loaded transformer circuit (RTx) is greater than the RRST rating (RRRST) then RTx in eqn. (10) becomes RRRST and u is determined as follows:

Then, Tx

RRST

LR

u×= 75.0

....................................................... (11)

Where, RRRST = rating of the rapid response spare transformer.

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The NCR capacity of a substation, that is, the actual capacity that a substation can be loaded up to under the NCR criterion is determined by the following equation:

���

���

��

� ��

� ×= ==

n

iTi

n

iTi RLuNCR

11

75.0,min .................................... (12)

Where:

u = NCR capacity factor.

LTi = Transformer MVA loading at substation peak time.

RTi = Normal cyclic rating of the ith transformer.

n = Number of transformers at a given substation.

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The following condition applies to eqn. (12) 7,

• If TiTi RLu >× , then the substation NCR capacity shall be scaled by

���

���

=Tn

Tn

Ti

Ti

uLR

uLR

s ,,min � .

Where:

u = NCR capacity factor.

LTi = MVA loading of the ith transformer at substation peak time.

RTi = Normal cyclic rating of the ith transformer circuit as per section 5.1.1.

n = Number of transformers at a given substation.

7 This condition takes into account the case where the rating of the heaviest loaded transformer is much

greater than the ratings of the other transformers in the substation.

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At zone substations where load balancing between transformers is poor, it is possible that the NCR capacity is less than the 1% Risk or even the Firm capacity. This arises because the NCR capacity takes into account unbalanced transformer loading, i.e. it’s effect on reducing substation capacity, in its calculation whereas the Firm and 1% Risk capacity do not. At three transformer zone substations where this occurs, it means that the calculated 1% Risk and/or Firm capacity at the substation cannot be fully utilised unless the load balance between transformers is optimal.

In such cases, as a general rule, the load balance between transformers should be improved to the degree where the NCR capacity is at least greater than or equal to the 1% Risk and/or the Firm capacity. This may be achieved by implementing some or all of the following measures:

• Re-arranging feeder circuits between transformers.

• Installing additional feeders to increase the symmetry of the LV busbar.

• Installing bus-section isolators to increase flexibility of the LV busbar configuration.

• Re-distributing load at the distribution network level.

In practice, a relative load unbalance of at least 10% between transformers is to be expected due to the discrete and changing nature of loads.

It is important to note, however, that carrying out some or all of the above does not guarantee that the full calculated 1% Risk and/or Firm capacity can be utilised. Each substation’s LV busbar and feeder configuration has to be examined on a case by case basis to maximise actual available 1% Risk and/or firm capacity. For planning purposes, it may be assumed that the NCR capacity is equal to the Firm or 1% Risk capacity, which ever is applicable, until the actual load balance after modifications are made is known.

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As with the 1% risk criterion, the repair of the failed transformer or a system spare transformer is required to replace the deployed RRST within a maximum of 10 days. The reasons are:

• The prolonged temporary installation of the RRST is less reliable than a permanent installation.

• To make the RRST available for another contingency.

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In three transformer substations with double LV busbar arrangements where transformers are not operated in parallel, the Firm, 1% Risk and NCR capacities are calculated as follows,

• Firm Capacity - DTC cannot be included in the substation’s Firm capacity because the third transformer cannot be connected to the LV busbars (ie. its capacity is not available until at least one of the operational transformers fail). Transformer load balancing on transformers supplying a double LV busbar arrangement is also assumed to be reasonable. It is assumed that as the substation load grows, the load on each of transformer grows in constant proportion with each other until the heaviest loaded transformer is loaded to a limit of 90% of the smallest transformer’s NCR.

Hence,

FC’ = NCRS1 + NCRS2 .................................................. (13)

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where, NCRS1 = smallest8 normal cyclic rating of the transformers in the substation.

NCRS2 = second smallest NCR of the transformers in the substation.

• 1% Risk Capacity does not apply to substations of this type because, as above, the third transformer cannot be connected to the LV busbar, hence its capacity is not available.

• NCR Capacity,

� Ideal NCR capacity = NCRL1 + NCRL2 ............................................................... (14)

where,

NCRL1 = largest NCR of the transformers in the substation.

NCRL2 = second largest NCR of the transformers in the substation.

Eqn. (14) applies because only two transformers can be operational at any one time if transformers are not run in parallel and clearly the two highest capacity transformers would be used. Effectively, three transformer double LV busbar substations have NCR capacities of two transformer substations.

� Actual NCR capacity is calculated as per eqn. (12) of section 5.2.3.4 assuming the lowest rated transformer is out-of-service. In all cases, the capacity of a substation is defined by the NCR capacity as per section 5.2.3.4.

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Perth’s CBD represents an important and sensitive load. Security and reliability of power supplies affect a large number of businesses, buildings and individuals. Therefore the planning criteria specific to the CBD are more onerous than for other areas of regional transmission supply.

The CBD boundary is shown in Figure 6. The CBD criteria are to be applied immediately within the short-term boundary, which is to be reviewed every five years. The planning criteria for Major substations (see Section 5.5) and the transmission lines interconnecting them are to apply outside the short term boundary and within the metropolitan area, however all new work within the long term boundary is to be carried out to facilitate future implementation of the CBD criteria.

8 The ratings of the smallest transformers are selected because it is assumed that in an N-1

contingency condition the largest transformer is out-of-service.

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The reliability criteria for CBD substations are outlined below.

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Contingency Criterion

N-1 (unplanned)

1. No loss of supply for line faults. 2. Supply may be lost for transformer or bus

(air insulated) outages but 100% load should be restored within 30 seconds.

N-2 (1 unplanned + 1 planned) or (2 unplanned)

1. Supply may be lost but 100% of the loads should be restored within 2 hours.

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Contingency Criterion

N-1, N-2 1. Supply may be lost but 100% of load should be restored within 2 hours.

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Contingency Criterion

Loss of MV bus section 1. Up to 24MVA may be lost (four feeders). 2. 100% of load should be restored within 1 hour. 3. Plant to be restored within 9 months.

Loss of front and rear MV busbars 1. Up to 36MVA may be lost (six feeders). 2. 100% of load should be restored within 2 hours. 3. Plant to be restored within 9 months.

Loss of complete zone substation (supply will be lost)

1. 100% of load should be restored in 4 hours or less.

2. Plant to be restored within 9 months. Notes:

• Circuit: includes lines (overhead or cable), transformers and busbars, but excludes circuit breakers.

• N-1 Contingency:

� The requirement for no supply interruption for N-1 line outages is considered too costly to implement in existing substations.

• N-2 Contingency:

� No individual substation needs to meet the N-2 criteria, however, the CBD substations should as a group. This means that load can be transferred between substations as long as the time constraints are met. A distribution automation system project which will accomplish this has been implemented.

� For two circuit outages to constitute an N-2 contingency they should together be more severe than a N-1 outage – one should make the other worse. Two unrelated outages, such as a feeder outage in one substation and a capacitor bank outage in another, would not constitute an N-2 contingency. A circuit out for maintenance, be it planned or not, can form one half of an N-2 contingency.

• Milligan and Hay Street are the only substations situated within the short term CBD boundary (see Figure 6. However, Wellington Street supplies a portion of the CBD load and is on the CBD boundary. It is considered a CBD substation for the purposes of the N-2 criteria.

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A zone substation is considered to be “Major” if it supplies a peak load of 20MVA or more. Major zone substation components are subject to the N-1 criterion with the exceptions outlined in Table 9. The transmission lines that interconnect Major zone substation are also subject to the N-1 criterion.

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Exceptions Substitute Restoration

Transformers

1% Risk or NCR Criterion as appropriate.

Note: Following distribution transfer, the 1% risk criterion and NCR criterion may result in continued load-shedding.

Distribution transfer to be carried out within 2 hours.

Load should be shed on a rotational basis until the load level drops below the firm capacity. Transformer replacement within 10 days under 1% Risk criterion or RRST deployment within an average of 9 hours under the NCR criterion if load shedding is required; otherwise as soon as practical.

Substation HV busbar Supply may be lost.

Load below substation firm capacity

• 100% restoration within 2 hours.

Load above substation firm capacity

• 100% of load supplied from unfaulted sections of the busbar to be restored within 2 hours.

• 100% of load supplied from faulted section of the busbar to be restored within an average of 9 hours, with the deployment of the RRST under the NCR criteria.

Transformer circuits

Supply from the relevant LV bus section may be lost

Note: Following distribution transfer, the 1% risk criterion and NCR criterion may result in continued load-shedding.

Distribution transfer to be carried out within 2 hours.

If load shedding is required, RRST deployment within an average of 9 hours provided RRST connections to the transformer LV circuit are not affected.

Substation indoor LV busbar

Supply from the relevant LV bus section(s) may be lost.

100% restoration within 48 hours (for metropolitan area substations) from the time when a safe working environment can be restored.

Note: This can be achieved by implementing the Rapid Response Standby Switchboard (RRSS) contingency plan.

Substation outdoor LV busbar

Supply from the relevant LV bus section(s) may be lost.

100% restoration within 48 hours (for metropolitan area substations) from the time when a safe working environment can be restored.

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Minor zone substations are those with peak load of less than 20MVA. Minor zone substation components are subject to the N-1 criterion with the exceptions outlined in Table 10. The transmission lines that interconnect Minor Zone substations are also subject to the N-1 reliability criteria with the exceptions outlined in Table 10.

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Exceptions Substitute Restoration

Single transformer substation without RRST backup.

N-0 criterion as appropriate.

Load in excess of that which can be supplied using DTC to be shed on a rotational basis until transformer replacement within 10 days.

1% Risk or NCR Criterion as appropriate.

Load should be shed on a rotational basis until the load level drops below the firm capacity or, in the case of the NCR criterion, until the RRST can be deployed. All supplies should then be restored. Transformers

[see guidelines below] Once the 1% Risk capacity is exceeded, provision of additional capacity should still be justified individually.

Standby generation or distribution transfer capacity may be used to provide partial restoration within 2 hours.

Transmission lines [see guidelines below]

Individual justification should be used to provide redundancy or sufficient distribution transfer capacity.

Standby local generation may be used to provide immediate restoration. In the case of substations supplied by single radial lines, line restoration to be provided within 1 to 2 days depending on the extent of damage.

Substation HV busbar Supply may be lost

Load below substation firm capacity

• 100% restoration within 2 hours. Load above substation firm capacity

• 100% of load supplied from unfaulted sections of the busbar to be restored within 2 hours.

• 100% of load supplied from faulted section of the busbar to be restored within an average of 9 hours, with the deployment of the RRST under the NCR criteria.

Transformer circuits Supply from the relevant LV bus section may be lost.

Distribution transfer to be carried out within 2 hours. Transformer replacement within 10 days under 1% Risk and average of 9 hours under NCR criterion if load shedding is required; otherwise as soon as practical.

Substation indoor LV Supply from the relevant 100% restoration within 48 hours (for

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Exceptions Substitute Restoration busbar LV bus section(s) may be

lost. metropolitan area substations) from the time when a safe working environment can be restored. Note: This can be achieved by implementing the Rapid Response Standby Switchboard (RRSS) contingency plan.

Substation outdoor LV busbar

Supply from the relevant LV bus section(s) may be lost.

100% restoration within 48 hours (for metropolitan area substations) from the time when a safe working environment can be restored.

Guidelines:

The following guidelines are to be used in conjunction with Table 10.

1. Substations with a peak load between 10MVA and 20MVA should normally have sufficient HV line infeeds to provide N-1 capability.

Exceptions would generally be at the discretion of any major customer at the relevant substation who may choose to forgo added reliability by not contributing financially to improving substation firm capacity.

Where exceptions are made:

1.1. Capacity should be maintained to ensure maintenance can be carried out at low load times without loss of supply.

2. Radially supplied minor substations or substation group (either 66kV or 132kV) with 100% backup.

2.1. These substations are normally supplied radially as it is not possible to connect in the backup supply without paralleling networks of dissimilar voltages, resulting in the risk of line overloads for N-1 outages in the higher voltage part of the network. As load grows, the situation may arise where the backup reduces below 100%. If this occurs, then it must be ensured that there is sufficient backup capacity to allow maintenance to be carried out at low load times.

2.2. In the case where the connected substation or substation group load has increased above 20MVA, additional infeeds to restore backup to 100% or N-1 capability are to be considered where the cost can be justified against customer benefit.

3. Transmission lines that supply a group of minor substations whose coincident peak load exceeds 20MVA are subject to the planning criteria as for a major substation. The exception is as for point 2 above.

4. For loads less than 10MVA, the level of redundancy should be dependent upon the type of load being supplied. Where economically viable, the philosophy assigned to loads between 10MVA and 20MVA should be applied as for point 1 above. For long country feeders in remote rural areas, the cost may be prohibitive. However, strategies should be in place to ensure restoration can occur as rapidly as possible.

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This section outlines Western Power’s policy regarding undergrounding of existing overhead transmission lines.

Western Power’s preference is to keep overhead lines whenever possible rather than undergrounding them for the following reasons:

• Overhead lines are a strategic long term asset. Overhead lines can readily be uprated in terms of voltage and capacity. For example, the ST-EP line started as a 66kV line and subsequently has been uprated to 132kV which allows its capacity to be doubled. This line is currently undergoing a change of conductors to further double its rating. These types of changes can be achieved cheaply on overhead lines but this is not the case if the line is converted to cable. The installation of small lowly rated sections of cable in a line should be discouraged.

• Cable costs are significantly higher than overhead line costs.

• The cost to convert a 66kV overhead line to 132kV is low. However, a 66kV cable cannot be converted to 132kV, it must be replaced at high cost.

• Faults on overhead lines can quickly be identified and repaired. With cable faults, it will normally take at least 2 days to repair.

However, if undergrounding of overhead lines are required, the following rules apply:

• Cable lives are in the order of 50 years. Any cable installed should be designed and rated for its expected service life.

• The 66kV systems are generally being retired and converted to 132kV to increase our power transfer capability. All 66kV overhead lines if undergrounded should be installed as 132kV cable, unless there is no prospect of the line being converted to 132kV in the next 30 years.

• Cable ratings should be matched to the highest rating that can be extracted from the overhead line. ie. The new cable rating should match the lines emergency rating (120°C), otherwise the cable will become a strangle point for the line and will have to be replaced at very high cost.

• Due to the long repair time for cable faults, when undergrounding an entire or a section of a radial overhead line, an additional fully rated cable or overhead line should be installed to cover the loss of one cable. This is to avoid causing extended outage while the cable is being repaired.

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This section outlines Western Power’s policy regarding upgrading of existing overhead transmission lines, or replacement of sections of a line. This policy does not apply to repairs.

The life of an overhead line is between 45 and 50 years. In some cases a steel tower line may last well beyond this time period. Any new transmission line asset must be rated for its expected service life.

The following rules apply during upgrading of transmission lines:

• Any upgrade must be designed and rated for the line’s expected service life.

• The 66kV systems are generally being converted to 132kV to increase power transfer capability. Where new poles, conductor or insulators are being installed on 66 kV lines they should be installed at 132kV, unless there is no prospect of the line being converted to 132kV in the next 30 years.

• In a line upgrade or other line works, if existing equipment is suitable for continued service it may be reused. However, where new equipment is installed it should be rated for the highest rating that can be extracted from the overhead line. The appropriate rating for emergency use is 120°C. If this is not followed this section will become a strangle point for the line. (Note the new high temperature conductors operate at temperatures in excess of 150°C and some as high as 250°C. The various sections need to be designed for the higher operating temperatures of these conductors)

• In the Metropolitan Area the standard conductor at 132 kV is Venus. New lines constructed in the Metropolitan area should be a minimum of a single Venus conductor. Where new equipment is installed on existing lines it should be capable of carrying Venus conductor. (Note the previous standard conductor was Triton. Some lines were designed and upgraded for Triton conductor. Triton conductor may be used instead of Venus on these lines if it is economical to do so.)

• New lines or sections are to include an overhead earth-wire or wires to provide adequate shielding.

• In country areas, the conductor size should be selected based on the power transfer needs of the line together with an economic analysis considering the cost of construction against the cost of losses over the lifetime of the line. Please refer to DMS# 1646420 (also DMS# 1327158 may be of interest).

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Appendix A: STANDARD RATINGS

All new primary plant shall be purchased in accordance with the minimum ratings specified in the relevant table below. For uprate/extension projects System Capacity section will specify the minimum requirements for each particular location.

These tables shall be read in conjunction with the following notes.

STANDARD TERMINAL STATION RATINGS System Voltage 330kV 220kV 132kV 66kV

Rated Voltage (kV rms) 362 245 145 72.5 1 Minute Power Frequency Withstand Voltage (kV rms) 520 460 275 140

Lighting Impulse Withstand Voltage across open switching device (kV Peak)

1175 1050 650 325

Switching Impulse Withstand Voltage (kV, Peak) 950 - - -

Normal Current (Amps rms): 330/132kV 132/66kV (a) Busbar Rating 3150 2500 3150 2500 1250 (b) 1 & ½ CB Bay Rating 2500 1250 2500 - (c) Line Circuit Rating 2000 1250 1600 1250 (d)Transformer Circuit Rating 1250 1250 2500 1600 1250 Short Time Withstand Current / Short Circuit Breaking Current (kA rms) 50 25 50 25

DC component as per AS62271.100 (Figure 9)

Generally τ = 45ms curve, but must be confirmed for each site.

Short Circuit Duration (s) 1 1 1 3 Total CB Clearing Time (ms) 40 40 60 60 Local Circuit Clearance Time (ms) 100 100 120 120 Remote Clearance Time (ms) (With intertripping) 140 140 160 160

Remote Clearance Time (ms) (Without intertripping) N/A 400 400 400

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STANDARD ZONE SUBSTATION RATINGS System Voltage 132kV 66kV 33kV 22kV 11kV

Rated Voltage (kV rms) 145 72.5 36 24 12 1 Minute Power Frequency Withstand Voltage (kV rms) 275 140 70 50 28

Lighting Impulse Withstand Voltage

outdoor 650 325 200 150 95

across open switching device (kV Peak)

indoor 550 325 170 125 75

Normal Current (Amps rms): 6.6kV or 11kV

(a) Busbar Rating 1600 1250 1250 1250 2000 2500 (b) Line/Feeder Circuit Rating 1600 1250 630 630 800 800 (c)Transformer Circuit Rating 6302 630 1250 1250 2000 2000 Short Time Withstand Current / Short Circuit Breaking Current (kA rms)

40 or 2517 25 16

or 1018 16

or 1018 25

25

DC component as per AS62271.100 (Figure 9) Generally τ = 45ms curve, but must be confirmed for each site.Short Circuit Duration (s) 1 3 3 3 3 Total CB Clearing Time (ms) 60 60 100 100 100 Local Circuit Clearance Times (ms) 120 120 17 & 18 See below comments: Subject to individual review and individual approval for zone substations in

the country areas.

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In addition to the above,

1. All components in the circuit shall meet the above minimum requirements.

2. Current transformers for 132kV zone substation transformer circuits shall have a minimum primary thermal limit current of 600A to match standard CT characteristics.

3. Earth wires, phase conductors and earth grids shall be rated in accordance with the minimum required clearing times and design fault ratings in Appendix D.

4. Local clearance time equals total circuit breaker clearing time plus total protection operation time, plus a margin.

5. Total protection operate time is taken as 40 ms.

6. Total communications operate time end to end is taken as 40 ms.

7. These clearance times are based on generally available standard inter-tripping protection schemes.

8. These or faster times are to be achieved where new equipment is to be installed unless CFCT’s dictate faster clearance times.

9. Where new protection is installed on existing primary plant with slower operating times than the times given in the table, the protection should only take the 40 ms assumed in this table to operate.

10. If CFCTS shorter than the total Clearing times are required then special equipment may be required to meet the requested times.

11. In some circumstances the communications operate times may not be able to be readily achieved with standard schemes, equipment, and existing bearers. In these cases the specific needs of the circuit should be reviewed.

12. Blocking schemes used on TEED lines may require extended remote clearance times. TEED lines should be dealt with on a case by case basis. Extended remote clearance times for TEED lines must be agreed.

13. In addition to the standard DC component requirements for 22kV and 11kV plant:

a. 16kA equipment shall be rated for 12.5kA with an X/R of 25; and

b. 25kA equipment shall be rated for 16kA with an X/R of 25.

14. For applications where 22kV plant will be initially operated at 6.6kV or 11kV additional current ratings are defined above (shaded).

15. For applications where 11kV plant will be initially operated at 6.6kV the current ratings shall be identical to those for 11kV plant.

16. The minimum ratings required for the generator circuits are not covered by this document. Please consult System Capacity section about the minimum ratings for this application.

17. In some country areas a lower standard fault level rating could be applied for HV equipment. In this case the Short Time Withstand Current / Short Circuit Breaking Current for 132 kV zone substations will be 25 kA (kA, rms). Such cases will be a subject to individual review and individual approval for zone substations in the country areas. Please consult System Capacity section for a lower fault level approval before proceeding with any plans or application.

18. In some country areas a lower standard fault level rating could be applied for LV equipment. In this case the Short Time Withstand Current / Short Circuit Breaking Current for 33 kV and 22 kV outdoor equipment in zone substations will be 10 kA (kA, rms). Such cases will be a subject to individual review and individual approval for zone substations in the country areas. Please consult System Capacity section for a lower fault level approval before proceeding with any plans or application.

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Appendix B: STANDARD LV BUSBAR DESIGN

Line 3

T2 T1 T3

Line 1 Line 2

Line 4 HV Busbar

LV Busbar

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Appendix C: USE OF DTC UNDER NCR CRITERION

This section has been included as an appendix for future consideration. More experience needs to be gained in applying the NCR criterion first before attempting to push the loading of at NCR substations any higher.

DTC can be included in the Reduced NCR capacity only if the following conditions are satisfied:

• Heaviest loaded transformer circuit rating is greater than the RRST rating.

• DTC is available on the section of busbar associated with the heaviest loaded transformer circuit.

• DTC is not supplied from another NCR substation.

• Maximum amount of DTC that can be included is,

TxRRSTTx RRDTC −= ..................................................... (1)

Where, DTCTx = maximum amount of DTC associated with the heaviest loaded transformer circuit that can be included.

Hence, if all the above conditions are satisfied then eqn. (14) becomes:

Tx

TxRRST

LDTCR

u+

= ...................................................... (2)

It is important to note that it is not recommended to include DTC because this can lead to overloading of the transformer beyond its NCR rating, as previously noted.

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Appendix D: RATING OF OVERHEAD EARTH WIRES, PHASE CONDUCTORS AND EARTH GRIDS

The minimum required clearing times and design fault ratings for the rating of overhead earth wires, phase conductors and earth grids at terminal stations and zone substations, are shown in the following table. These ratings include allowances for the extra heating effect of the DC offset, which are discussed in detail below. DMS document # 2187772 provides distance versus fault level graphs for standard 66, 132, 220 and 330 kV transmission lines.

REQUIRED TERMINAL / ZONE SUBSTATION PLANT RATINGS

(Overhead Earth Wires, Phase Conductors, Earth Grids)

132kV System Voltage 330kV 220kV

Metro Country* 66kV

Overhead Earth Wires, Phase Conductors & Earth Grids

Short Time Withstand Current (kA)

56 28 56 / 45 27* 27

Overhead Earth Wires

Short Time Withstand (ms) 200 200 230 230 400

Phase Conductors Short Time Withstand (ms) 270 370 280/400 400 1000

Earth Grids Short Time Withstand (ms) 500 500 500 500 1000

* Subject to individual review and individual approval.

NOTES:

• These ratings are applicable at the substation/ terminal station only, as the fault level and DC offset reduce significantly as the distance between the substation/terminal station and the fault increases. Please refer to the ‘Fault Level vs Distance’ charts to determine the fault level along the line.

• For substations with high double phase to earth fault levels, the ratings in the table may need to be increased.

• A local backup clearance time of 270ms is used for new 330kV and 220kV sites. A local backup clearance time of 310ms is used for new 132kV sites.

• The local backup clearance times of existing 330kV, 220kV, and 132kV sites shall be improved to 270/310ms as sites are uprated from 40kA to 50kA. Please confirm existing fault levels with the System Capacity Manager.

• The earthing system shall be designed in accordance with relevant standards, including AS2067, and shall include N-1 redundancy for earth conductors and earth connections.

• For railway crossings, an earthwire that can withstand the 270/400ms of a circuit breaker failure should be used, at the ultimate fault level of 60/48kA (330/132kV).

• All OPGW earth wires are to be designed to withstand a fault cleared in local backup time (LBU) to prevent damage to the optic fibre.

• In some country areas a lower standard fault level rating could be applied. In this case the Short Time Withstand Current / Short Circuit Breaking Current for 132 kV conductors and earthwires will be reduced to 27 kA. Such cases will be a subject to individual review and individual approval for zone substations in the country areas. Please consult System Capacity section for a lower fault level approval before proceeding with any plans or application.

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The fault currents provided are the ultimate design fault levels required to ensure that plant will meet the thermal duty imposed by Western Power’s standard ratings, taking into account the extra heating effect of the DC offset (X/R).

Installations designed to the new standard will meet the following ‘base’ ratings:

STANDARD TERMINAL STATION / ZONE SUBSTATION RATINGS

132kV

Zone Sub System Voltage 330kV 220kV Terminal

Metro Country*

66kV

Short Time Withstand Current (kA)

50 25 50 40 25 * 25 Overhead Earth Wires Short Time

Withstand (ms)

200 200 230 230 230 400

Short Time Withstand Current (kA)

50 / 40 25 50 40 25 * 25 Phase Conductors & Earth Grids Short Time

Withstand (ms)

270 / 370 370 310 400 400 1000

* Subject to individual review and individual approval.

The new ratings are devised by applying a suitable ‘design factor’ to the ‘base’ ratings such that;

• The extra heating effect from the DC offset in the current waveform is included, assuming an X/R of 14, and worst point on wave fault occurrence.

The ‘design factors’ are given as follows.

Time (ms)

DC offset

‘Design Factor’

100 20.0%

200 10.6%

250 8.6%

270 7.9%

400 5.4%

500 4.4%

1000 2.2%

The minimum required fault clearing times are based on analysis provided by Protection (ref. DMS #1324100v2) that indicates:

Local fault clearance times of 105ms and less are achievable on new circuits with new protection.

Circuit breaker failure clearance times of 270ms and less are feasible on new 330kV circuits with new protection. Circuit breaker failure clearance times of 310ms and less are feasible on new 132kV circuits with new protection.

On existing circuits, reduction in breaker failure clearance times by 40ms can be achieved by reducing the very conservative 100ms safety margin presently used in the LBU time delay. Further reductions in times may require changing circuit breakers and protections.

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Actual clearance times will be dependent on a number of factors (eg the protection selected, the actual trip operating time of the circuit breaker, operating time of adjacent breakers, etc) – the actual clearance time that can be achieved will thus need to be assessed on a case by case basis. In this regard, it is proposed that System Capacity will outline the required clearance times in planning documentation (eg planning criteria, estimate requests).

In summary, the maximum time for which a local fault is cleared at new sites with new protection, without a CB failure, is 105ms. The maximum time for which a local fault is cleared by backup protection (LBU), at new sites with new protection, is 310ms.

The local backup (LBU) clearance times (CB fail) may be used to rate phase conductors and earth grids. This design is in accordance with ‘normal practise’ indicated in AS2067, and the ‘Safearth’ design of the earthing system for the Cockburn switchyard. Note AS2067 suggests the use of an additional margin (ms). However, an additional safety margin may be provided, by ensuring the earthing system is designed to a (N-1) level of redundancy for all earth conductors and earth connections. Note the contribution of remote fault currents to the phase conductor fault current is minimal. An additional safety margin is included for earth grids (total withstand time 500ms) due to their buried location and associated maintenance difficulties.

For the rating of overhead earth wires some additional risk may be taken by using the local fault times (with no CB fail) to rate overhead earth wires. However, it is possible for one or two bays of earth conductor to be damaged, in the unlikely event of a breaker failure for a close-in fault. In the case of such an event, the failure of the earth wire may not necessarily result in loss of supply or increased safety risk. Any damage shall be identified during post-fault line inspection. Therefore, a clearance time of 200ms is chosen for overhead earth wires, such that the conductor will withstand the fault current plus one attempt to reclose onto the fault (note there will be some cooling of the earth wire during deadtime). Again, the contribution of remote fault currents to the earth wire fault current is minimal.

At existing sites, the maximum time for which a local fault is cleared, without a CB failure, may be up to 200ms (or 1s @ 66kV). The maximum time for which a local fault is cleared by backup protection, at existing sites, may be up to 400ms (except 66kV) for design fault levels up to 40kA.

At existing sites, it will be necessary to improve the local backup clearance times to 270/310ms, at the time of uprating the site to the ultimate design fault level (50kA).

In the interim, when installing new plant at existing terminal stations and zone substations, provided the plant is designed for ultimate operation at the design fault levels listed in table 2, the plant will be adequately rated for present fault levels and clearing times, based on an equivalent I2t analysis.