primary network design manual

Version: 1 Date of Issue: October 2007

Author: Dave Charlesworth Job Title: Senior Network Design Engineer

Approver: John Simpson Job Title: Head of Network Engineering

Primary Network Design Manual


Version: 1 Date of Issue: October 2007 of 118

The master version of the this document resides in the E.ON UK Documentum database CAUTION – any other copy may be out of date

© Central Networks plc

REVISION LOG

Version 1 Prepared by Dave Charlesworth Date October 2007 First issue





CONTENTS

1 OVERVIEW 6 1.1 CONNECTION TO THE TRANSMISSION NETWORK 6 1.2 GSP SUPPLY GROUPS 6 1.3 PRIMARY NETWORK VOLTAGES 7 1.4 11KV NETWORK INFEED 7 1.5 NETWORK PHASE ARRANGEMENTS 8 1.6 EARTHING ARRANGEMENTS 9 1.6.1 132kV Network 9 1.6.2 66kV and 33kV 9 1.6.3 11kV (or 6.6kV) 10

2 DESIGN PRINCIPLES 11 2.1 INTRODUCTION 11 2.2 CONNECTIVITY PLANNING STANDARDS 12 2.3 SINGLE CIRCUIT SUPPLIES 13 2.3.1 Design Principles 13 2.3.2 Design Criteria 15 2.4 TRANSFER CAPABILITY 15 2.4.1 Design Criteria 17 2.5 COMPLEXITY 19 2.5.1 Design Criteria 21 2.6 NETWORK RESILIENCE 21 2.6.1 Flood 21 2.6.2 Storm 22 2.6.3 Malicious Acts 22 2.7 SECURITY OF SENSITIVE SUPPLIES 22 2.8 SEASONAL AND CYCLIC LOAD 23 2.9 LOSSES 23 2.10 DISTRIBUTED GENERATION 24 2.11 PROTECTION, CONTROL AND AUTOMATION 25 2.11.1 Introduction 25 2.11.2 Design Criteria 26 2.12 ASSET AND CONFIGURATION STANDARDS 27

3 SUBSTATION LAYOUTS 28 3.1 INTRODUCTION 28 3.1.1 General Information 28 3.1.2 Complex Sites 28 3.1.3 Fault Throwing Switches 29





3.2 132KV NETWORKS 29 3.2.1 Double Busbar Substations 29 3.2.2 Simple Radial 132kV Substation Arrangements 33 3.2.3 132kV Mesh Substations 37 3.2.4 132kV Double Circuit Transfer Arrangements 42 3.2.5 132kV Single Circuit Transfer Arrangements 44 3.3 66KV NETWORKS 45 3.4 33KV NETWORKS 46 3.4.1 General 46 3.4.2 33kV Source Substations 49 3.4.3 Radial Networks 51 3.4.4 Special Radial Arrangements 56 3.4.5 Rural 33kV Networks 58 3.5 11KV SWITCHBOARD 59

4 NETWORK CONNECTIVITY 60 4.1 GENERAL INFORMATION 60 4.1.1 Overview 60 4.1.2 Flexibility 60 4.1.3 Cascade Tripping 60 4.1.4 Voltage Levels 61 4.1.5 Engineering Recommendation P18 – Complexity of 132kV Circuits 61 4.2 PREFERRED ARRANGEMENTS 62 4.2.1 Sub Transmission Networks 62 4.2.2 Radial Distribution Networks 71 4.2.3 Ring Networks 82

5 NETWORK EQUIPMENT 87 5.1 TRANSFORMERS 87 5.1.1 Standard ratings and Impedances 87 5.1.2 Tapping range 89 5.1.3 Vector Group 89 5.1.4 Standard Connections 90 5.2 OVERHEAD LINES 90 5.2.1 132kV Network 90 5.2.2 66kV Network 93 5.2.3 33kV Network 93 5.3 UNDERGROUND CABLES 94 5.3.1 132kV 94 5.3.2 66kV 94 5.3.3 33kV 94





5.4 SWITCHGEAR 95 5.4.1 Specifications 95 5.4.2 Switchgear Ratings 95

6 GUIDANCE NOTES 97 6.1 ENGINEERING RECOMMENDATION P2/6 97 6.1.1 Class of Supply 97 6.1.2 Group Demand 97 6.1.3 Typical Network Arrangements 98 6.1.4 First Outage Requirements 98 6.1.5 Second Outage Requirements 100 6.1.6 Interpretation of Multiple Sites 102 6.2 FIRM CAPACITY 107 6.2.1 First Outage 108 6.2.2 Second Outage 109 6.3 PROTECTION ISSUES 110 6.3.1 Pitfalls with multi-substation ring networks 110 6.3.2 Protection issues with teed rural networks 112 6.4 RING NETWORKS 113 6.5 PRIMARY NETWORK DESIGN 116 6.5.1 Transformer Replacement 116 6.5.2 132/33kV, 120MVA transformers 117 6.5.3 Transformers with Dual Secondary Windings (132/11/11kV or 66/11/11kV) 117 6.5.4 Switchgear Fault Ratings 118





1 OVERVIEW

1.1 CONNECTION TO THE TRANSMISSION NETWORK

The transmission network in England and Wales operates at 275kV and 400kV providing interconnection between Distribution Network Operators (DNO’s) primary networks, major generating stations and interconnection across national borders. The transmission operator is responsible for maintaining a balance between energy demand and generation, thus, maintaining system frequency within statutory limits. The transmission network is operated as one interconnected network. Central Networks obtains a connection to the transmission network at Grid Supply Points (GSP’s). The connection voltage is exclusively 132kV for CN (East), CN (West) have connection at 132kV and 66kV. The DNO network is referenced against the RED phase of the Transmission Network, this is defined as being at 0° or 12 o’clock.

1.2 GSP SUPPLY GROUPS

It is Central Networks policy to operate each GSP independently. Where interconnecting 132kV circuits exist to provide transfer capability between GSP’s they are operated with open points. Generally the benefits derived from parallel operation of GSP’s are more than offset by the complexity of network analysis and effects of excessive fault levels. Analysis for network planning purposes (including protection design) requires the parameters of the transmission network to be modelled for normal and abnormal conditions with worst case minimum and maximum demands (and generation infeeds) to ensure excessive circulating currents are not present in the primary network. Analysis in real time is virtually impossible, faults on the third party (NGT) 400kV or 275kV network may cause excessive loading of CN circuits with subsequent protection operation and potential loss of customer supplies before the control engineer has time to react. Transfers between GSP’s are normally made ‘on load’, ie, GSP’s are interconnected at 132kV (or 66kV) during switching time (typically less than one minute). During the time of the parallel connection the fault levels of the two networks will increase and in some circumstances exceed equipment ratings. However, due to the short duration of the parallel operation this risk is minimal.





It is common practice for more than one DNO, or DNO’s and generators, to share a GSP connection points. At shared sites it is the convention that the transmission operator owns the 132kV busbar and the DNO’s own the equipment in their circuit bay up to the busbar isolator busbar clamps (or gas barrier for GIS switchgear). At GSP’s connecting just one DNO it is the convention for the DNO to own the 132kV busbar and the transmission operator to own their own transformer bays up to the busbar isolator busbar clamps (or gas barrier for GIS switchgear). Operational and Planning arrangements between the DNO and the Transmission Network Operator are defined in the Grid Code.

1.3 PRIMARY NETWORK VOLTAGES

CN operate with 3 primary voltage levels, 132kV, 66kV (CN West only) and 33kV. The principle function of the primary network is to provide a supply to the 11kV distribution network, and comprises a 132kV sub transmission and distribution network, and a medium voltage distribution network with voltage levels of 33kV and 66kV. Although the vast majority of customers are connected at 11kV and below there are a few major customers connected directly to the primary network. The primary network provides a synchronising connection with the transmission network for embedded generation within Central Networks. The 132kV network differs fundamentally from the medium voltage network in that it is electrically connected to the NGT transmission network via auto (single winding) transformers. Due to the inherent design features of auto transformers the vector grouping of the 132kV network is fixed to the NGT standard (RED phase at 0° or 12 o’clock), and, transformers have a single neutral connection (thus, earthing arrangements are common for both primary and secondary transformer neutral connections). The 33kV and 66kV networks are connected to the 132kV network (or the NGT transmission network in the case of the 66kV network) by two winding transformers (magnetically coupled). As the transformer secondary winding is electrically independent from the primary the two windings can have different configurations and independent earthing arrangements.

1.4 11KV NETWORK INFEED

The 11kV network is supplied from all primary voltage levels, ie, 132/11kV, 66/11kV or 33/11kV. As with the 33kV and 66kV networks transformation to 11kV is by double wound transformers (or





triple in the case of 132/11/11kV units) and thus enables various options in the configuration of the 11kV winding (see section 1.5).

1.5 NETWORK PHASE ARRANGEMENTS

Network vector groupings are as shown in Table 1.

Table 1 –Network Vector Groups

Voltage Level Degrees Vector Group Comments

400kv (NGT) 0 12 o’clock

275kV (NGT) 0 12 o’clock 132kV 0 12 o’clock

66kV +30 1 o’clock 33kV +30 1 o’clock See note 1

11kV (CN East) 0 12 o’clock See note 2 11kV (CN West) Various See note 3

Note 1:

Some parts of Lincolnshire (CN East) are marked with red phase at the 9 o’clock (-90º) position, where this connection exists it is being brought into line with the CN standard as network modifications take place. Note 2:

The Toyota car manufacturing plant at Burnaston (CN East - Willington supply group) has a 1 o’clock (+30º) connection. However, this supply has no 11kV interconnection with other parts of the CN network. Note 3:

For historical reasons, the phase displacement across the CN West 11kV network is not consistent. See Long Term Development statement for details.





1.6 EARTHING ARRANGEMENTS

1.6.1 132kV Network

The neutral point of 400/132kV or 275/132kV transformer windings is solidly earthed (zero impedance) at the GSP. The benefit of this arrangement is that during phase to earth faults the healthy phases remain at a relatively constant nominal system phase to earth voltage thus reducing insulation costs. However, earth fault currents are relatively high typically 20% higher than for phase to phase faults. All transformers at BSP’s with 132kV primary windings (star connected) have their neutral points solidly bonded to earth. As a result a network phase to earth fault will result in current flow through the neutral to earth connections of all transformer primary windings connected into that GSP network. High phase to earth fault currents have the potential to create excessively high Rise of Earth Potential at substation sites requiring particular attention when designing substation earthing systems. It is CN policy to provide a continuous earth conductor on all 132kV circuits between substations. The earth conductor is connected to the main earthing system (metallic earth bonding system) at each substation and provides a return path for fault currents reducing the current flow to earth and hence reducing ROEP. For steel tower overhead lines the earthing conductor provides a means of bonding support steelwork to earth at each tower position. 132kV overhead line systems are available using wood pole supports with no earth conductor. Any design utilising this type of construction must include a risk assessment stating;

• The effects on the BSP substation ROEP when energised from a circuit with no continuous earth conductor between that BSP and the source GSP

• How the ROEP is maintained within limits for network phase to earth faults on any cable sheath or metallic structure forming part of that circuit .

1.6.2 66kV and 33kV

As the secondary windings of transformers supplying the medium voltage network are DELTA connected a neutral connection point is not available at the network transformer. To enable earth fault detection a neutral point is provided by a separate earthing / auxiliary transformer. Phase to earth fault current is limited by series impedance is in the fault path and can be provided as zero sequence reactance in the earthing / auxiliary transformer primary winding or





as an external resistance connected between the earthing transformer primary winding neutral point and the substation earth. The position of the zero sequence impedance affects network voltages during earth faults

• With an external NER and a zero impedance fault the faulted phase is at earth potential with minimal volt drop in the transformer winding, causing the healthy phases to rise in voltage to line voltage levels relative to earth potential.

• With earth fault current limited by the zero sequence impedance of the earthing / auxiliary transformer primary winding, its neutral point solidly earthed and a zero impedance fault, the faulted phase will be at earth potential. However, the internal volt drop in the transformer winding will be relatively high (ie its terminal volts will decrease significantly) resulting in minimal neutral – earth voltage displacement, hence the non faulted phases have a minimal phase to earth voltage increase.

Current policy on the method of earthing, and earth fault current limits, are described in “Central Networks Application Guide – Primary Transformer Earthing”.

1.6.3 11kV (or 6.6kV)

The secondary windings of transformers supplying the 11kV network are either STAR or DELTA connected dependant on the vector group of that network. Earthing arrangements are as described in section 1.6.2.





2 DESIGN PRINCIPLES

2.1 INTRODUCTION

The objectives of the design principles are to: • provide the rationale for the rules in the design manual, especially in terms of balancing

network performance, risk and capital cost; • ensure that the design rules are consistent and support the network performance

objectives; • provide background on the view of future requirements of the network and what (if

anything) is planned to accommodate each requirement; and • ensure that the network shall be designed to comply with all statutory and licence

conditions. Network performance and risk has been understood by considering both the fault history of the network and its inherent physical characteristics and configuration. The impact of these on business performance through, for example, performance incentives schemes (IIP) has been assessed to review the prioritisation of network improvements. This will continue in an enhanced Network Review process, reflecting the objectives of the regulatory incentives. Investigation of major network incidents, resulting in high CI and CML counts, has identified some common causes of failure. Where network design principles have been identified as a contributory factor to poor network performance this has been considered and improvements for design established. It is recognised that in many cases other factors have impacted network performance that are outside the control of the network designer. However, design for operability is a key aspect, enabling ease of restoration or of outage planning. It is intended that all modifications to the primary network should be designed to meet these principles. The principles provide an understanding of the rationale for design rules in the manual so that appropriate decisions can be made about the specifics of any design situation. These principles are based on finding an appropriate balance of cost, performance and risk and these should be considered specifically in any design work. Application of the principles is therefore subject to these considerations but should be deviated only where a clear and overwhelming financial case can be demonstrated. Consideration has been given to the application of these principles retrospectively across the network. This has been assessed using the same objective of balancing cost, risk and performance (including incentive benefits). Risk in this case covers both the risk rating of the





current configuration and the risk associated with making a change to the network. Alternative strategies have been defined from this work which will feed into the investment plans:

• Strategic action - programmes of network wide proactive change where investment is justified;

• Selective action - retrospective “upgrade” of the network in high impact areas to achieve significant benefits at acceptable cost; and

• Opportunistic action - “upgrade” opportunities taken at marginal extra cost where other issues drive network change.

The following sections cover each of the design principles in detail, describing the reasoning behind each one and the design criteria that have been concluded.

2.2 CONNECTIVITY PLANNING STANDARDS

Primary Network connectivity shall be designed to meet the standards shown in Table 2 below:

Table 2 – Planning Standards

Ref Title Comments

Statutory Instrument 2002 No. 2665

The Electricity Safety, Quality and Continuity Regulations 2002

Section 27 - frequency and voltage requirements

The Grid Code DNO / TSO obligations

The Distribution Code DNO / Customer obligations

CN Power System Operations Manual

ER G5/4 Planning levels for harmonic voltage distortion and the connection of non-linear equipment to transmission and distribution systems in the United Kingdom.

Harmonics

ER G59/1 Recommendation for the connection of private generating plant to the Public Electricity Suppliers’ distribution systems.

All generation

ER G75/1 Recommendations for the connection of embedded generating plant to public distribution systems above 20kV or with outputs over 5MW.

Additional requirements for larger generators





Table 2 – Planning Standards (Continued)

ER P2/6 Security of Supply.

ER P18 Complexity of 132kV Circuits Ends and Addresses rule

ER P14 Preferred switchgear ratings.

ER P24 AC traction supplies to British Rail. Single phase traction supplies

ER P28 Planning limits for voltage fluctuations caused by industrial, commercial and domestic equipment in the United Kingdom.

Flicker

ER P29 Planning limits for voltage unbalance in the United Kingdom for 132kV and below.

Unbalanced Load

ER S34 A guide for assessing the rise of earth potential at substation sites.

Earthing

2.3 SINGLE CIRCUIT SUPPLIES

2.3.1 Design Principles

Supplies to all customers with a group demand greater than 1MW require some means of restoring supplies during outage of the normal supply circuit to meet the requirements of ER P2/6, therefore for loss of a single primary network circuit there will always be an alternative means of connecting customers. In most cases there will be two primary circuits operating in parallel, the parallel connection is normally made at the busbar of the of the lower voltage network switchboard at a transformation point. In some circumstances a parallel connection is not desirable, there are four fundamental reasons for not operating the primary network with a parallel connection as they may result in:

1. Potentially high circulating currents (parallels across two GSP’s) 2. Increased complexity of network analysis 3. Increased protection complexity 4. fault levels exceed network ratings

Note: Interconnection between 2 GSP supply sources can lead to all of the above.





CN operates sections of the primary network with single circuit supplies and switched alternatives to:

1. avoid interconnection of two GSP’s 2. avoid overstressing of the network 3. provide low cost 33kV supplies to rural areas where voltage regulation is problem

The Design Criteria does not rule out the use of single circuit primary supplies, however, it does reduce the absolute number of customers placed at risk and also limits the combined risk of customer numbers and restoration times. Where supply circuits are not paralleled the customer is effectively served by a single circuit primary network with supplies restored by a switched alternative. During a fault outage the minimum time for supply restoration is defined by ER P2/6 and restoration will be either local manual, remote manual, remote automated or local automated as required for compliance. All restoration methods result in loss of supplies to customers during switching time. Remote restoration relies on the integrity of the control system and its communications. Local manual restoration is relatively slow due to travelling times. The time threshold for Customer Interruptions (CI’s) under the Information and Incentives Project (IIP) is 3 minutes, thus where automated restoration is available supplies will normally be restored without incurring CI penalties. Delays in restoration over the three minute period also results in the application of Customer Minutes Lost (CML) penalties, providing an additional incentive to restore supplies quickly. Local manual restoration will therefore tend towards high CML penalties. CI risk increases proportionately to the number of customers supplied from the connection point, CML risk is a product of customer numbers and time to restoration. These principles are designed to minimise exposure to IIP risk by reducing both the number of customers supplied by a single primary circuit and restoration times In view of the above the preferred arrangement is to operate with parallel connections wherever possible as:

1. It avoids supply losses providing improved service to the customer 2. avoids the requirement for automation schemes where failure may result in CI’s (and

potentially CML’s) 3. Local manual restoration times are excessive resulting in CML’s





2.3.2 Design Criteria

A single circuit supply shall not be used where the number of customers at risk exceeds 6,000. Where a supply group is supplied from more than one feeder it is permissible for each individual feeder to supply a maximum of 6,000 customers per independent circuit, i.e. a duplicate feed could supply a maximum of 12,000 customers (6,000 per feed) The total number of consumers that shall be disconnected from the supply for loss of a single circuit and the required method of restoration are defined in Table 3:

Table 3 – Maximum Customers at Single Circuit Risk

Customers Equivalent MVA Switching Method

Up to 2,000 Up to 4 Local Manual

2,000 to 4,000 4 to 8 Remote Manual

4,000 to 6,000 8 to 12 Automated

6,000 or more >12 Parallel Supply only

Notes:

• A proxy of 2kVA per customer may be used to simplify design limiting a single circuit supply to 12MVA per circuit, ie, a 24MVA primary substation operated with an open bus section.

• Where restoration switching is at a single substation site and all data inputs to the scheme are located at that site the automation scheme shall not be reliant on communications with the control centre for its operation.

• For transfer of open points embedded on the 11kV network automated switching by sequence scheme is acceptable.

2.4 TRANSFER CAPABILITY

In order to meet the requirements of ER P2/6 the majority of the primary network requires a minimum of two feeder circuits to each substation or group of substations (supply group). Although loss of both feeder circuits is rare these incidents have the potential for producing high CI and CML counts.





Class D supply groups with group demand between 100MW and 300MW require a minimum of three main supply circuits, (or two main circuits and sufficient transfer capability) to maintain supplies to up to one third of customers in the group during outage of two main circuits. It is possible to remain compliant with ER P2/6 and disconnect supplies to up to 200MW of demand (approximately 100,000 customers) during the time to restore the planned outages. Restoration of planned works may be several weeks during construction works, this is an unacceptable IIP risk. Normally such incidents occur while one circuit is out of service for maintenance or during network modifications and the second circuit trips on fault. The severity of the incident depends on the type of fault and the item of equipment that has faulted. An overhead line fault due to lightning disturbance, followed by a successful auto re-closes, will cause a short time interruption (< 3 minutes). However, a transformer fault on one circuit during an outage for transformer replacement on the other has the potential for a prolonged loss of the main supply to a substation for several days or weeks. The risk to customers’ supplies for a double circuit outage is reduced by:

1. Reducing the number of customers of each supply group 2. Increasing the number of main supply circuits into the supply group 3. Increasing transfer capability between supply groups

Transfer capability can be utilised during a planned outage, and prior to supply loss, to reduce the number of customers at risk. During emergency conditions it is usually possible to increase the number of customers transferred to adjacent supply groups by utilising abnormal running arrangements. For transfer capacity to be effective the distance between substations of adjacent supply groups must also be considered. Excessive distances may result in reduced transfer capability due to voltage regulation. After all transfer capability has been exhausted the use of LV mobile generation can be considered to supply the remaining customers. Generation has little impact on IIP risk of the primary network as the timescales involved in obtaining and connecting the generation is excessive. To make any substantial impact on IIP risk the means to restore supplies must be available within a few hours.





Higher capacity 11kV generation is unproven and not recommended as a strategy for supply restoration as:

1. Costs are excessive, both rental and fuel, 2. Requires provision of an adequate network earth, 3. Ability of protection systems to operate correctly at low fault levels is suspect, 4. Physical size is prohibitive in locating a suitable connection point, and lack of existing

connection points into the network An active spares policy is also essential for mitigating long term outage risk due to faults as manufacturing timescales for main equipment items are in the order of 6 to 10 months. However, this will have little impact on IIP risk during routine network outages, eg construction works or maintenance due to excessively long installation times.


Identifying customer numbers at each connection point during network analysis for normal and abnormal running arrangements is impracticable. Network demand is used as a proxy for customer numbers (based on 2kVA per customer) with transfer capability expressed in terms of demand rather than customer numbers. Generally as demand increases the number of main circuits required to provide supply security also increases. This improves the ability to retain supplies during second outage conditions and is reflected in the increase in demand retention / transfer capability requirement. For the purposes of this criterion main circuits are deemed to be at the highest voltage level feeding into the load centre, transfer circuits are deemed to be either at the same voltage level or at a lower voltage level than the main circuits. The residual demand requiring generation support is provided to limit the number of customers whose supplies cannot be restored from the network within 18 hours.





The following criteria in Table 4 show minimum levels of retained demand and transfer capability during second outage conditions (fault outage during planned outage):

Table 4 - Transfer Capability Group Demand (MVA)

Minimum Demand retained immediately post fault (% of prefault demand)

% demand to be retained / transferred within

Worst case residual demand requiring generation support

Notes

15mins 3 hours 18 hours MVA

<100 0 30 40 50 50 1,2

100 to 150 20 45 60 70 45 1,2,3

150 to 300

50 60 70 80 60 1,2,3

>300 100 0 4

Notes:

1. Where possible designs shall be used that reduce the risk of customer interruptions during a planned outage by,

a. automated transfer within 3 minutes of the fault outage occurring due to the characteristics of the network

b. automated transfer within 3 minutes by auto load transfer scheme c. pre fault transfer (if possible without increasing the probability of loss of supplies

to the customers transferred) 2. During the normal and abnormal running arrangements described above all connected

consumers shall be supplied within statutory voltage limits.

3. Appropriate measures must be in place post first circuit outage to safeguard against cascade tripping of the remaining circuit(s) due to overload (operation of overcurrent protection) in the event that a second circuit is lost.

4. ER P2/6 requires all consumers to be restored immediately (ie, loss of supply not exceeding 60 seconds) for group demands exceeding 300MW. Where this is achieved by transferring demand at single circuit risk the demand per transfer circuit shall not exceed 100MVA.

The worst case generation support is based on maximum demands. In practice planned outages are normally between the period April to October when maximum demands are typically 80% of the winter MD.





2.5 COMPLEXITY

Networks have generally become complex where there are a limited number of circuits from the source substation to the load centre. As demand has grown firm circuit capacity has become inadequate requiring capital investment in new circuits. Rather than provide new circuit capacity from the source substation networks have been interconnected and operated with multiple parallels so that the circuits of one section of network provides mutual support for another. Although this practice provides a cost effective solution for each incremental step of interconnection the network becomes less robust as increase in demand results in increasing reliance on the circuits emanating from the source substation. Complex networks are an impediment to real time decision making leading to delays in restoration times. Protection, the safety system behind the power system, has to function effectively during normal, abnormal and extreme network operating conditions. Complex networks generally have an elevated number of credible running arrangements making them difficult to asses, especially in relation to identifying fault level scenarios. Protection schemes and settings become complex and often entail a great deal of compromise with a consequential elevation of risk of incorrect operation (or non operation) and human error during commissioning and maintenance. Generally complex networks connect large numbers of customers with risk of extremely high IIP penalties. The simplest network arrangement is a double circuit transformer feeder with a parallel on the transformer secondary circuit. Any failure on one circuit either due to a fault, or human error during planned works, is unlikely to affect customer’s supplies. A mesh arrangement, including a simple cross bay arrangement, has circuit breakers connected across two supply circuits and is thus susceptible to a common mode failure. Work on the network during planned outage of one circuit results in increased risk of loss of supplies as active protection components (CT’s) of the ‘live’ circuit are connected in the work zone of the circuit under outage. Complex network arrangements generally suffer from the following disadvantages:

• high risk of faults caused by human error; • can be impossible to grade with standard back up protection;





• some arrangements are impossible to grade using standard main protection schemes (distance protection);

• power flows cannot be predicted without computer analysis and are difficult to manage in ‘real time’;

• difficult to establish which items of equipment have failed (in real time) due to multiple protection relay operations resulting in supply restoration delays, and;

• difficult to manage network planned outages due to the limited number of feeder circuits into the network from the supply source, outages can produce unacceptable network risks.

Categorisation of complexity:

• Simple – transformer feeders • category 1 – single substation with cross bay, ie 3 transformer supplied from 2 circuits • category 2 – series of substations connected in a ring, each substation using a cross bay

arrangement to control the ring circuit. One teed circuit may be connected to the ring circuit between substations provided that;

o it is terminated by transformer(s), and, o the teed circuit does not interconnect with another ring network

• category 3 – Where up to 4 circuits are interconnected remote from the source substation, using an approved means of interconnection, eg, interconnection of two ring networks.

• category 4 – either; o Where up to 4 circuits are interconnected remote from the source substation

where the means of interconnection is not approved, eg, interconnecting circuits without discrete protection of the interconnector

o As above with more than one interconnection point o Where the number of interconnected circuits exceeds 4.

Note: category 3 networks do not include networks comprising three or more circuits directly connected from a source substation to an approved interconnection point, eg, an embedded double busbar substation. Such circuits are classed as sub transmission networks and are acceptable provided the means of interconnection is approved. Interconnecting circuits normally operated as open points are not deemed to add to network complexity and thus are not included in any of the above classifications.






• Radial or simple ring networks are preferred (see section 4.2.3.1 for extensions to ring circuits)

• Category 3 should be avoided where possible but may be used for future extensions to the network provided that all circuits are connected to the same source GSP. Approved methods of interconnection for category 3 networks are shown in section 4.2.3.2.

• Category 4 networks shall not be used for future extensions • Where investment is planned to existing category 3 and 4 networks consideration should

be given to simplifying the network connection

2.6 NETWORK RESILIENCE

Network assets are designed to be resilient under most operational conditions, however, under extreme circumstances network performance may be compromised particularly due to floods, storms and malicious acts. Where network performance is vulnerable under these extreme circumstances the feasibility of enhancing the design should be considered. For specific guidance refer to the relevant Central Networks asset manual.

2.6.1 Flood

Areas within the 1 in 200 year flood contour should be avoided when locating future substation sites. For all new primary substation sites measures shall be taken to ensure that 1 in 1000 year flood levels do not reduce network security and critical operational equipment (and access to it) shall be installed above the 1 in 1000 year contour level. A list of typical critical equipment is provided below;

• primary equipment terminations • relay / control panels • telecoms / scada equipment and its communication connections • marshalling kiosks • terminal pillars • batteries and chargers, including LVAC supplies • transformer tapchange and cooling LV supplies





Where possible the ground level of buildings, compounds and access routes shall be raised to mitigate the risk. Existing sites which are vulnerable to flooding will have flood protection measures incorporated into the design of future modifications based on the flood risk. Flood risk will be assessed by the site position relative to flood contours, e.g. the 1000 year flood contour.

2.6.2 Storm

Experience has shown the areas that are most at risk from storms. In these areas network design will take account of this higher risk and use design measures that reduce the incidence of damage.

2.6.3 Malicious Acts

Criticality of assets and strategic risk from malicious acts will be part of the design consideration. Where criticality and vulnerability are sufficient, the design will include measures to improve physical security.

2.7 SECURITY OF SENSITIVE SUPPLIES

In general, customers choose the level of security they require to meet the needs of their particular circumstances. However, in a small number of situations it may be appropriate for Central Networks to ensure that a greater level of security or resilience is afforded to an individual or group of customers. Where appropriate, measures to improve supply security will be part of the design. Examples of such situations – Major entertainment venues Large city centres Major media centres Major airports Major traction supplies





2.8 SEASONAL AND CYCLIC LOAD

Traditionally winter demand against enhanced winter equipment ratings has provided the trigger for network reinforcement and summer demand was assumed to be within 67% of winter demand. Summer demands are now typically 80% to 85% of winter ratings and in some circumstances may be the trigger for network reinforcement. For network review, and, when considering connection of new customers to the network, the effects of seasonal load must be taken into consideration. Additionally, many items of network equipment are operated based on a cyclic rating. In some instances (particularly for industrial or city centre demands) the actual load profile will be flatter than that assumed to rate the equipment and in such cases the cyclic rating must be reduced. Where there is insufficient data (either in respect to the load shape or the equipment thermal characteristics) the continuous rating shall be used.

2.9 LOSSES

The effect of network losses should be considered during connectivity design and when specifying equipment, however, this must be balanced with equipment and installation costs. Some factors influencing losses are:

• Utilisation – lower circuit utilisation results in lower losses for an equivalent circuit resistance (losses are proportional to the square of the current)

• Circuit resistance (losses are proportional to resistance), thus larger conductor size will result in reduced losses

• Transformer losses, - the subject of transformer losses is complicated in that they are subject to both iron and copper losses. Iron losses can be reduced by using more expensive core steels and reducing flux density (increasing the size of the core) and copper losses by increasing the cross sectional area of the windings, all these methods increase manufacturing costs. For a particular transformer the iron losses are proportional to the voltage across the winding and thus are practically constant when a transformer is energised regardless of demand, copper losses are proportional to the square of the transformer loading (I2R). Other influences on losses are;





o Paralleling transformers, the greater number of transformers on the network the higher the standing iron loss, however, copper losses are reduced as the demand per transformer is reduced.

o Direct 132/11kV transformation has a potential benefit of reducing iron losses when compared with 132/33kV followed by 33/11kV transformation, however, this will normally be offset by increases in 11kV network losses,

o Transformer impedance – this affects circuit losses, particularly on long circuits. High transformer impedance tends to increase VAr flow in the circuits and hence circuit copper losses.

2.10 DISTRIBUTED GENERATION

The primary network is designed to enable connection of generation, however, depending on the size and type of generation the following effects of a generation connection must be considered;

• Increases in fault levels • Voltage control and statutory voltage limitations (particularly over voltage) • Voltage step change • Network thermal constraints (particularly during periods of minimum demand) • Power flow monitoring (particularly for circuits with both demand and generation

customers connected) • Transformer reverse power flow

o some transformer tapchanger diverters are not designed for switching during reverse power flow

o directional overcurrent protection may be operated during periods of reverse power flow where standard protection settings are applied

• For large generating stations (>100MW) typically connected to the 132kV network where ability to remain connected during network disturbances is required. Stability studies may be required to ensure fault clearance times are adequate. Studies may reveal the requirement for extensive circuit breaker and protection replacement.





2.11 PROTECTION, CONTROL AND AUTOMATION

2.11.1 Introduction

There is a statutory duty to protect the public from the effects of faults on the network. When a fault occurs it is also desirable to ensure that the adverse affects of high fault current is minimised. The primary network is protected using fault detection equipment to initiate a trip signal and circuit breakers to de-energise the faulted section of circuit. Control equipment may be used to automatically restore supplies following intermittent faults (lightning) and to automate restoration of supplies to healthy sections of circuit following permanent faults. Primary network protection use a system of lower voltage secondary circuits to replicate the main power system with voltage transformers (VT’s) providing a voltage reference and current transformers (CT’s) providing a current reference. For simple overcurrent protection CT’s only are required. A voltage reference is primarily required for directional protection and distance protection schemes, and also for automatic voltage control of transformers. CT’s and VT’s also provide a means for remote indication of real time network loadings and voltages. The primary network is divided into protection zones; zone boundaries being defined by the fault detection equipment (normally CT’s and VT’s). Not all faults are detected by excessive fault current, for example, with transformer winding faults other forms of detection are necessary and for this type of fault ‘Buchholz’ protection is used to detect the presence of gasses produced by the heating or electrical arcing effects on the insulating oil. Having detected a fault it is desirable to remove the supply source as quickly as possible. Circuit Breakers are used on the primary network to break fault currents. Their position on the network is critical to performance as one or more CB’s will be tripped (opened) on detection of a fault. The numbers of customers disconnected during this operation will be influenced by the position and configuration of circuit breakers. Not all circuit breakers form part of the network protection system, at 132kV circuit breakers are used for switching operations on the ‘live’ network. On 132kV ‘ring networks’ circuit breakers are used to disconnect supplies to a section of network that extends beyond a protection zone, the protection system relies on motorised isolators to disconnect the faulted protection zone and the circuit breakers re-close to restore supplies to the healthy sections.





There is always the possibility that the main protection system will fail to operate and so back up protection is required to cover for this eventuality. In order to reduce costs the requirements for back up protection is not as onerous as that of the main protection schemes. Some forms of main protection inherently provide back up protection for adjacent zones (distance protection) whereas others do not (unit protection).


While designing modifications to the network it is essential that the protection and control systems are incorporated to ensure that;

• protection zones are designed with consideration for limiting the number of customers affected by a fault

• the network is designed such that primary protection systems will operate within prescribed timescales for a fault within the protection zone and not operate (unless designed as a function of back up protection) for faults outside of the zone;

• protection zones shall have back up protection systems that are graded with the main protection systems and do not to operate before the main protection systems.

• 132kV main protection schemes shall be designed to clear network faults within 120mS (in line with section CC.6.2.3.1.1 of the grid Code), however, this may be delayed by a further 500mS to enable grading between protection zones

• For 33kV and 66kV networks, where fault throwers are used for communication of transformer faults, it is permissible to extend fault clearance times by a further 400mS to allow for operation of the fault thrower.

• Back up protection schemes shall be designed to clear network faults within 3 seconds; • Circuits that are predominantly overhead shall be fitted with automated reclose control

equipment • Circuits that are predominantly underground cable shall not be fitted with automated

reclose equipment. • any proposed circuit configuration can be protected to meet these protection design

criteria using standard manufactured equipment without the need for bespoke equipment;

• costs of ancillary protection equipment are accounted for during network design, eg, CT’s, VT’s, pilot circuits etc.; and

• sufficient space for protection equipment is allowed for when considering the layout of substation equipment.





2.12 ASSET AND CONFIGURATION STANDARDS

Providing standards for configuration is a primary objective of this network design manual. The configuration of the network has a direct impact on the long term performance characteristics and on the near term operability of the system. The design principles here have considered the alternatives applied across the network (especially across East and West) and provide a common set of configuration standards as a basis for all design work. These configuration standards aim to maximise benefits to the company through the best balance of cost and performance. They also seek to deliver an increased level of operability that comes both through the easy-to-operate configurations and through fewer configuration varieties. This will lead to easier outage planning with lower outage risks and faster restoration of supplies. Asset standards are not part of the objective of this design manual.





3 SUBSTATION LAYOUTS

3.1 INTRODUCTION

3.1.1 General Information

This section of the manual provides a library of standard arrangements for substation equipment. The purpose of the library is to standardise substation connectivity and enable standard protection schemes to be employed with the benefit of:-

• reduced design time, • eliminate design errors, • standardised site layouts • reduce risk of commissioning errors • provide consistency to operators

Arrangements show the equipment required for operability but are not operational diagrams, generally diagrams do not show:-

• earthing switches • CT’s and VT’s • Earthing / auxiliary transformers • NER’s • Other minor equipment

Lower voltage switchgear is shown for completeness but does not show positions of isolating devices, earthing switches, CT’s and VT’s. It is recognised that standard arrangements are not always applicable for all situations thus bespoke arrangements may be approved by the Network Design Manager. Otherwise all new installations or modifications and extensions will be designed to these standards.

3.1.2 Complex Sites

Substation physical layouts shall conform to section 6.3 of the Power System Operations Manual.





3.1.3 Fault Throwing Switches

Substation arrangements are based on eliminating fault throwing switches on the 132kV network. At 66kV and 33kV they will continue to be an accepted method of communicating transformer faults to remote supply sources unless other approved means of communication are available for intertripping. Rented communication circuits will not be used solely for the use of transformer protection communication at any primary voltage level. At 132kV the fault throwing switch is replaced by a transformer circuit breaker (where private communication circuits are unavailable for intertripping). A live tank circuit breaker only is needed as there is no requirement for CT’s. Transformer protection will trip this local circuit breaker to clear a fault.

3.2 132KV NETWORKS

3.2.1 Double Busbar Substations

Grid Supply Point 132kV substations will be double busbar configuration as shown in figure 3.1. New substations will typically be supplied by two Supergrid Transformers (SGT’s) initially and the arrangement of figure 3.2 can be used provided sufficient land is purchased at the outset to extend and accommodate a minimum of four SGT’s. The number of circuits shown is indicative, an assessment of the total number and hence land requirements will be required during detailed design. The drawings show a reserve busbar circuit breaker, this is an enhancement from previous designs and is included to provide improvements to flexibility in operation when substations are operated with a bus coupler ‘split’ to reduce fault level. At shared sites the transmission operator will have ownership and control of the busbar, bus section, and bus coupler circuits and thus inclusion of the reserve busbar bus section circuit breaker is not directly under CN’s control. The principle of operation is common for both AIS and GIS installations. All double busbar substations shall be designed to enable modification, replacement or extension with no more than one section of busbar made dead at any time.





Unit type busbar protection will be used for the main busbars with conventional overall and discrimination zones.

Figure 3.1 – Double Busbar 132kV Substation, 4 SGT’s

MainBusbar

ReserveBusbar

SGT

SGT

SGT

SGT

Circuit

Bus Coupler

Bus Coupler

BusSection

Circuit

Circuit

Circuit

BusSection





Figure 3.2 – Double Busbar 132kV Substation, 2 SGT’s

MainBusbar

ReserveBusbar

SGT

SGT

SGT

SGT

Circuit

Bus Coupler

Bus Coupler

BusSection

Circuit

Circuit

Circuit

BusSection

Future Extension





Figure 3.3 shows a standard bay arrangement suitable for connection of one outgoing circuit. Unless there are special circumstances no more than one circuit per bay will be connected. During major substation reorganisation banked circuits will be separated to provide one switchbay per circuit.

Figure 3.3 – Standard Bay Layout

Circuit

Main Busbar Reserve Busbar

MainBusbarIsolator

ReserveBusbarIsolator Circuit

Isolator

Where it is not practicable to provide a separate bay for a new circuit the arrangement in figure 3.4 may be used to provide additional security. This arrangement also provides the opportunity to operate a circuit that would otherwise exceed the maximum number of addresses specified in ER P18, ie, a 5 address circuit can be operated as 2 x 3 address circuits. Each feeder circuit shall have dedicated feeder protection.

Figure 3.4 – Banking of 2 circuits at one bay





3.2.2 Simple Radial 132kV Substation Arrangements

Figure 3.5 shows the simplest arrangement of a radially connected 132kV substation.

This example shows a 2 transformer arrangement, this can simply be extended to a three transformer (on 3 circuits) arrangement for 66kV and 33kV secondary voltages. The connection of 3 x 132/11kV transformers in parallel is not recommended due to excessive fault levels on the 11kV network.

Transformer circuit breakers are used to clear transformer faults (Duo Bias unit protection and Buchholz) eliminating the need for fault throwers and intertripping circuits. Live tank units are acceptable as there is no requirement for CT’s.

Transformer unit protection CT’s are mounted in the transformer HV bushings and LV switchboard incoming circuit breaker.

132kV circuit protection from LV backfeed is provided by Directional Overcurrent protection, CT’s and VT’s mounted on the LV switchboard incoming circuit breaker.

Figure 3.5 – Radial Transformer Feeder





Figure 3.6 shows the application with a transformer having double secondary (11kV) windings. The principle of operation of the 132kV network is as described in the previous example.

Figure 3.6 – Radial Transformer Feeder with 132/11/11 Transformer





The arrangement of 3.7 is generally designed for transformation to two lower voltage networks, eg, 132/33kV and 132/11kV using the principles shown in figure 3.5. It also provides an alternative to the arrangement of figure 3.6 (using 4 x 132/11kV, 30MVA transformers) with the benefit of standardised voltage control and improved security during planned transformer outages.

Figure 3.7 – Radial Transformer Feeder with Banked Transformers





Where private communication systems are available between the transformer substation and the supply source the arrangement shown in figure 3.8 may be used eliminating the need for the transformer circuit breakers. Future provision should be made for installation of a circuit breaker as a contingency for loss of the private communications. This arrangement is most suitable for cable connected substations where pilot cables have been laid alongside the power cables.

Figure 3.8 – Radial Transformer Feeder on Cable Circuit





3.2.3 132kV Mesh Substations

Mesh arrangements provide a means of effectively producing multiple protection zones without the need for each zone to be controlled by a dedicated circuit breaker. They were developed at a time when 132kV circuit breaker costs were relatively high, however, 132kV circuit breakers costs have significantly reduced relative to protection and other costs. The principal of operation is that a transformer or permanent feeder circuit fault will initiate tripping of circuit breakers to make a section of network dead, the section of network initiating the trip is isolated automatically and the circuit breakers reclose automatically once the faulted section is isolated. Mesh corner faults should be detected by dedicated mesh corner protection (rather than an extension to the circuit protection) as busbar faults are normally permanent. The preferred mesh corner arrangement is limited to two circuits per mesh corner, ie 2 transformers, 2 feeder circuits or one of each to reduce complexity of protection and automation schemes. Mesh arrangements can either be closed or open. A closed mesh is impracticable with fewer than 3 circuit breakers and as most 132kV circuits are double circuit tower lines the most common form of closed mesh is a four switch mesh. The advantage of a closed mesh is that all in service circuits remain interconnected during a mesh corner outage resulting in maximum optimisation of circuit loading. However, an open mesh does have the advantage of providing n+1 discrete connection points (where n = number of mesh circuit breakers).





Open Mesh Arrangements Figure 3.9 shows a 2 transformer mesh substation, whereas a radial arrangement would typically have both circuits connected to the same remote substation the ring arrangement may be supplied from more than one source provided that both sources are in the same GSP supply group.

Figure 3.9 – Single Switch Open Mesh, 2 Transformers





Position of mesh corner CT’s are shown for mesh corner 1 and line CT’s for circuit 1, the same principle is used for mesh corner 2 / circuit 2. Figure 3.10 shows a 3 transformer arrangement with a third feeder circuit. Position of protection CT’s are shown for MC 2. MC 1 and MC3 arrangements are as described in figure 3.9. All circuits must be connected to the same GSP supply group. See figure 3.16 for arrangement with circuit 2 connected into a different supply group to circuits 1 and 3.

Figure 3.10 – Double Switch Open Mesh, 3 Transformers

Circuit 3Circuit 1

A

A

A A

A

GT1 GT2 GT3

A

Circuit 2

Position of Mesh cornerprotection CT’s for MC 2

Position of Feeder circuitprotection CT’s for circuit 2

MeshCorner 1

MeshCorner 2

MeshCorner 3

132kV 132kV

66kV, 33kV or 11kV 66kV, 33kV or 11kV





Closed Mesh Arrangement Figure 3.11 shows a four switch closed mesh arrangement. This design was originally used for interconnecting transmission circuits and is still used by transmission operators. Examples can be found on the 132kV network but in many cases the arrangement is not appropriate for a distribution network and other alternatives should be considered (see figure 3.12). Figure 4.3a, 4.3b and 4.3c shows typical network 4 switch mesh network arrangements. A four switch mesh arrangement is normally used to interconnect two double circuits from a supply source with ongoing feeder circuits and local transformation. Many existing sites interconnect double circuits from different GSP’s and thus have to be operated with open points on the circuit isolators, others do not comply with the criteria for number and combination of circuits connected to each mesh corner and have bespoke hardwired auto reclose systems. Although a 4 switch mesh arrangement is the most common a higher number of circuit breakers could be used to increase the number of discrete connection points if required.

Figure 3.11 – Four Switch Closed Mesh

Circuit

CircuitCircuit

A

A

Circuit

A

A

A

A

A

A

Circuit

Circuit

132kV





Line Circuit Breakers The substation arrangements of figures 3.9, 3.10 and 3.11 all require some form of communication between substations so that local protection schemes (busbar and transformer protection) will trip circuit breakers at remote substations prior to auto isolation and reclose. Where the communication system is rented from a third party (typically overhead line circuits using rented BT circuits) it may be cost effective to replace the circuit auto isolator (at all circuit ends) with circuit breakers and manually operated circuit isolators. Figure 3.12 shows the equivalent arrangement as figure 3.9 to achieve this, the same principal holds for the arrangements of figures 3.10 and 3.11. The circuit breakers may be live tank with a single set of post CT’s (as shown) or a dead tank circuit breaker could be used with CT’s mounted in the bushing turrets providing the facility to overlap the circuit and busbar protection zones.

Figure 3.12 – Mesh Substation with Line Circuit Breakers





3.2.4 132kV Double Circuit Transfer Arrangements

Figure 3.13(a) shows the standard arrangement for interconnecting two double circuits at a transformation substation. GT1 and GT2 are normally supplied from GSP1 with the circuit breakers providing an open point between the two GSP supply groups.

Substation demand can be transferred remotely by telecontrol to GSP 2 by dead transfer resulting in the running arrangement of figure 3.13(b). Alternatively live transfer may be possible by closing the circuit breakers at the BSP and opening the feeder circuit CB’s at GSP 1.

The arrangement is primarily designed for overhead line feeder circuits using distance protection at the source GSP’s with the reach of the protection set to cover the whole circuit between the two GSP’s. This enables the circuit breakers at the BSP to be used for on load switching, with no requirements for CT’s and circuit protection.

Where other BSP’s are connected to the main 132kV circuits and intertripping is required as part of the circuit protection scheme the in line circuit breaker shall be equipped with distance protection and the intertripping scheme separated into two schemes each one covering the zone between source GSP and the in line circuit breaker.

Double Circuit Transfer Figure 3.13(a) – Normal Operation Figure 3.13(b) – Load Transfer





Figure 3.14 shows how four transformers are connected.

Figure 3.14 – Double Circuit Transfer with Banked Transformers





3.2.5 132kV Single Circuit Transfer Arrangements

The arrangements of figure 3.15 and 3.16 are primarily designed to enable load transfer to take place for compliance with ER P2/6 security standards with class D supplies (group demand in excess of 100MW). Although the transfer circuit may be connected to the same GSP supply as the main circuits the third circuit would typically be connected to another GSP. This has the added advantage of enabling load transfers between GSP’s Typically the BSP shown in figure 3.15 will be connected to a network with teed feeders, where the total demand exceeds 100MW, and transfer of one BSP is sufficient for compliance.

Figure 3.15 – Single Circuit Transfer, Radial Network

Circuit toGSP 2

GT1 GT2

Circuits to GSP 1

M M

132kV 132kV

66kV, 33kV or 11kV





The arrangement of figure 3.16 provides transfer capability where a cross bay is used to provide a secure transformer mid point connection. In this case the demand of the single substation may exceed 100MW, remaining P2/6 compliant on transformer capacity but requiring a third circuit to cater for a double outage of the incoming supply circuits.

Figure 3.16 – Single Circuit Transfer, Ring Network

Circuit 2GSP 1

Circuit 1 - GSP1

A

A

A A

A

GT1 GT2 GT3

Circuit 3 - GSP2

66kV, 33kV or 11kV 66kV, 33kV or 11kV

132kV 132kV

3.3 66KV NETWORKS

66kV primary networks are used in CN West only. Network configuration is similar to that of the 132kV network except that impedance earthing is used, thus phase to earth fault currents are relatively low and potential rise of earth potential can be easily controlled.





These characteristics allow the use of fault throwers (that are precluded at 132kV) and the use of unearthed overhead line feeders. In many respects the 66kV network is a hybrid of the 132kV and 33kV networks and is generally designed to supply rural areas with a minimal number of supply points. Due to the lengths of circuit a 33kV supply network would to be prohibitive due to poor voltage regulation. The 66kV network suffers from three main disadvantages;

1. It prohibits interconnection of 132kV networks resulting in low capability for load transfer during outages particularly between GSP’s

2. 66kV overhead line designs must conform to IEC 60826 (Overhead Transmission Lines at 45kV and Greater) leading to increased network costs when compared to a 33kV alternative.

3. Operating with an additional primary voltage level to 132kV and 33kV results in another level of network overheads in expertise, spares, data holding etc.

Due to the above this network should not be designed to expand beyond its existing geographical boundary. During asset replacement, or when network reinforcement is required, the feasibility of uprating to 132kV should be explored.

3.4 33KV NETWORKS

3.4.1 General

3.4.1.1 Characteristics of 33kV Networks

132kV and 33kV networks characteristics are different resulting in changes to the approach to connectivity design as highlighted below;

1. Reduced earth fault current due to impedance earthing enabling; a. potential for reduced rise of earth potential b. smaller sites with higher earth mat resistance c. the use of fault throwers as a means of communication of transformer faults to

remote substations 2. Circuit MVA capacities reduced (same current level results in 25% MVA capacity

compared to 132kV) generally leading to fewer customers connected per circuit and acceptability of higher fault rates and less costly protection methods.

3. More susceptible to voltage regulation problems resulting in reduced feed area





33/11kV Substation designs are provided to cater for the following types of 33kV network:

1. Urban 2. Semi Urban 3. Rural

The radial networks described in section 3.3 and 3.4 typically apply to urban and semi urban networks and comprise of direct circuits or circuits with no more than one tee connection. These arrangements may apply to rural feeders in some circumstances particularly where voltage regulation becomes an issue but generally rural supplies enable a greater number of substations to be connected from a pair of standard 24MVA or 40MVA circuits. Rural circuit arrangements, both radial and ring, are shown in section 3.5 Urban: Urban network arrangements apply to cities or large towns with one or more BSP’s within the urban area. Circuits are generally cable connected and a single substation demand is expected to approach the limits of its dedicated circuit capacity. Typically this will be a substation with 2 x 24MVA or 2 x 40MVA 33/11kV transformers with radial connected circuits. Semi Urban: Semi urban networks are generally similar in topology to urban networks but would typically supply large towns or business parks / industrial areas remote from the BSP. Circuits are typically a mixture of underground and overhead construction. In many cases circuits are simple dedicated connections to a single 33/11kV substation supplying a high demand areas. As networks develop it is not unusual to find teed or banked circuits to other substations, in some cases single circuit supplies to outlying rural areas. In many cases double circuit wood pole overhead lines are in service, these suffer from insufficient clearances between circuits requiring double circuit outages when working in proximity to the conductors. All future designs using wood pole construction shall be single circuit.





Rural: Rural networks are typically overhead construction providing supplies to small towns or villages. Substation demand is normally relatively low and several substations may be supplied by a pair of feeder circuits, a large proportion of substations will be connected by single circuit at 33kV with restoration at 11kV by transfer of open points.

3.4.1.2 Pole Mounted Air Break Switch Disconnectors

The justification for pole mounted ABSD’s must be made on the basis of the economic benefit in reducing IIP risk against increased installation costs and capitalised costs of inspection and maintenance. Reduction in IIP risk shall be made on the basis of;

• Numbers of customers affected, • Length of circuit and unit length fault rate, • For firm connections the percentage of time customers are at risk during planned

outages, • IIP bonus / penalty regime

3.4.1.3 Pole Mounted Auto Reclosers

PMAR’s should only be considered were standard protection schemes at circuit terminations provide unsatisfactory clearance times.

3.4.1.4 Ring Main Units (RMU)

The switchgear arrangements shown in this section may be provided using RMU’s where a cost effective equivalent arrangement to the examples shown are available.





3.4.2 33kV Source Substations

3.4.2.1 Single Busbar Substations

The standard arrangement for new 33kV primary single busbar substations is shown in figure 3.17. The arrangement is based on an indoor metal enclosed switchgear installation. A three transformer supply, with two bus section switches, can be accommodated where network fault ratings permit. A three section busbar arrangement may also be used where a three circuit network connection is required.

Figure 3.17 – 33kV Switchboard

Transformer 1

CIRCUITS CIRCUITS

Transformer 2

3.4.2.2 Switchgear Extension

When all spare feeder bays have been used it is permissible to bank two circuits on one feeder switch provided both circuits are of the same type, the thermal rating of the feeder bay (including CT’s) is adequate, the resultant configuration is compliant with ER P2/6, and, the circuits can be suitably protected. When the above conditions cannot be met and further connections are required an assessment should be made for extending the switchboard, if possible with the same type of switchgear. Normally the existing switchgear is obsolete and unless decommissioned units are available the only means of extension is by a ‘joggle box’ busbar connection. In many instances particularly with outdoor ‘weatherbeater’ type switchboards this is impracticable and uneconomic. If the existing switchboard is due for asset replacement it should be replaced at this time by a new board. If the existing switchboard is not due for asset replacement a new section of board should be installed and interconnected as shown in figure 3.18.





The configuration enables firm double circuit connections between bus sections 1 and 2, 1 and 3, and, 2 and 3. Also firm triple feeder connections can be made if required. When the original section of board becomes due for asset replacement the configuration should be retained with the original switchboard only being replaced. The interconnector circuit shall have circuit breakers at each end and be protected by a unit protection scheme that trips the interconnector only and maintains supplies to the switchgear busbars The number and position of feeder bays on the new section of switchboard should be assessed at the time and shall provide sufficient circuit breaker bays for one feeder circuit per bay and spares for anticipated future bays within the timescales of the development plan. Provision of a second switchboard should also be considered when uprating transformer capacity at a site using the same criteria as above.

Figure 3.18 – 33kV Switchboard Extension In

terc

onne

ctor

3.4.2.3 Outdoor 33kV Substations

Outdoor substations suffer from; • malicious acts (vandalism and theft) • risk of trip due to wildlife, eg, birds, cats etc • higher maintenance costs, and, • higher safety risk due to exposed live busbars





Extension of 33kV outdoor substations should not be considered as they are normally time expired with relatively poor condition infrastructure.

3.4.3 Radial Networks

The standard arrangements of figure 3.19 to 3.20 are used for radial primary substation connections. Typical networks are shown in figures 4.8, 4.10, 4.11, 4.12, 4.17 and cover most requirements for urban and semi urban radial networks. Three transformer 33/11kV substation arrangements are shown in figures 4.11 and 4.12. Single circuit arrangements for rural radial networks are shown in figures 4.7 and 4.10.

3.4.3.1 Cable Connected Circuits

Figure 3.19a shows a direct supply with no isolator at the transformation substation. This design shall be restricted to modifications of existing installations already directly connected in this way (eg transformer replacement) and where the following criteria are met;

• the supply circuit is not banked or in anyway shares a source circuit breaker with another circuit,

• the circuit is cable in its entirety from source circuit breaker to transformer cable box, • private pilot communications are available (normally a pilot cable laid with the main

power cable) New 33/11kV substations shall not be connected in this way and where practicable the connection shown in figure 3.19b shall be used for cable circuits with private pilot cable intertripping.





Cable Connected Circuits

Figure 3.19a Figure 3.19b Figure 3.19c

Circuit

T1

33kV

11kV

Circuit

A

T1

33kV

11kV

Circuit 1

A

M

T1

Circuit 2

11kV

33kV

Figure 3.19b shows the requirement where another circuit is banked at the supply source or teed along the route of the circuit. All transformers sharing the common connection point must have auto isolation facilities. Note: cable joints for teeing from 400sq mm cable are not available, if this arrangement is required it will be necessary to either bank the second circuit at source or tee at the remote 33/11kV substation as shown in figure 3.19c.

3.4.3.2 Overhead Connected Circuits:

Figure 3.20a shows a standard transformer connection supplied by overhead line, from either a dedicated supply or where a second circuit is banked at the supply source or teed at some point on the circuit. Figure 3.20b shows the arrangement for an ongoing circuit connection within the 33/11kV substation.





Overhead Line Connected Circuits

Figure 3.20a Figure 3.20b

Circuit

FT

A

T1

11kV

33kV

Circuit 1

FT

A

M

T1

Circuit 2

11kV

33kV

Where suitable private communications exist between the substation and supply source intertripping may be used and rather than fault throwers for transformer protection.

3.4.3.3 Mixed Circuits

Mixed Overhead Line and Cable Connected Circuits Figure 3.21a Figure 3.21b

Ongoing cable circuit: The substation in figure 3.21a is supplied by overhead line with an ongoing cable circuit. The substation connected to circuit 2 arranged as figure 3.19a or 3.19b.





Circuit 1 to be protected by distance protection with zone 1 set to reach 80% up to the tee point with zone 2 reaching into transformer T1 HV winding and into circuit 2. Auto reclose is required for zone 1 faults only. A fault thrower is used for communication with the source circuit breaker for transformer faults. Transformer isolation provided by local intertripping to LV circuit breaker and HV auto isolation. The ongoing circuit 2 will normally be protected by hi-set protection at CB ‘A’. Auto reclose shall not be provided on this cable circuit. Ongoing overhead circuit: The substation in figure 3.21b is supplied by cable with an ongoing overhead circuit. The substation connected to circuit 2 arranged as figure 3.20a. Circuit 1 to be protected by distance protection with zone 1 set to reach 80% up to the tee point with zone 2 reaching into transformer T1 HV winding and into circuit 2. Auto reclose shall not be provided on circuit 1 (cable). Communication with the source circuit breaker (circuit 1) for transformer faults will be provided by pilot wire intertripping. Transformer isolation provided by local intertripping to LV circuit breaker and HV auto isolation. The ongoing circuit 2 protected by hi-set protection at CB ‘A’ with auto reclose.





3.4.3.4 Banked Feeders

Figure 3.22 – Banked Feeders

Circuit 2(banked)

Circuit 1

FTFT

A A

FT

A

T1 T1T2

SUBSTATION A SUBSTATION B

11kV 11kV

33kV 33kV

The preferred method of connection to a 33kV switchboard is one feeder per circuit breaker. However, when networks develop it is sometimes necessary for two feeders to share one common circuit breaker. Circuit operation is similar in principal to a teed feeder. Normally circuits are banked to utilise the relatively high thermal capacity of the feeder bay, typically 800A or 1250A (and in some instances 2000A), that is not available from a tee connection. Banked connections shall not be used where the variance in circuit impedance of the two circuits exceeds 20%. The arrangement of figure 3.22 shows two circuits banked to one circuit breaker at the supply source. Substations A and B are shown with the overhead connection arrangement but the principle holds for cable connected. Substation B may be a single transformer site or one of 2 (or more) transformers connected to the lower voltage switchboard.





3.4.4 Special Radial Arrangements

3.4.4.1 33/11kV substations supplied from two BSP’s

Figure 3.23 shows the arrangement for a 33/11kv substation with each transformer supplied by different BSP’s. The arrangement is particularly useful for providing load transfer capability between the two BSP’s during BSP transformer circuit outages. The arrangement shown is for overhead line connected 33kV circuits, cable circuits may be used for one or both circuits and where pilot cables are available the fault throwers can be removed. Network arrangement is shown in figure 4.13.

Figure 3.23 – 33/11kV Substation supplied from 2 BSP’s

M M

T1 T2

Circuit 1 Circuit 2

A A

FTFT

BSP1 BSP2

11kV

33kV

One particularly useful application of this arrangement is to supply two 33/11kV substations from a double circuit would pole line and still maintain a firm supply to both substations during a double outage of the circuit, see figure 4.14. This is a preferred arrangement for 33/11kv substations located approximately midway (typically 30% to 70%) between two BSP’s supplied from the same GSP. The arrangement of figure 3.23 provides facility for feeding through the primary substation during supply failure to one of the BSP’s to energise that BSP 33kV busbar.





3.4.4.2 BSP interconnecting circuits

The three diagrams of figures 3.24a, 3.24b and 3.24c show applications of interconnecting circuits between BSP’s that supply 33/11kV transformers. The substations may be single transformer substations or may be one circuit of two or more feeding the substation. The normal running arrangement is to supply the 33/11kV transformer from one or the other BSP, and by moving open points it is possible to transfer load between BSP’s. A direct interconnector between two BSP’s has limited application under normal network operation as the load on a 33kV busbar is usually much higher than the interconnector circuit capacity. However, situations arise during developments of the network, particularly when new BSP’s are installed and connected to existing 33/11kV substations, where interconnections become available. During emergency operation, say for loss of the infeed into a BSP, backfeeding the 33kV busbar (after transferring as much load as possible) can drastically reduce the number of customers off supply.

BSP Interconnecting Circuit Arrangements Figure 3.24a Figure 3.24b Figure 3.24c

Figure 3.24a shows the requirements for connection when both circuits are overhead construction and the tee point is remote from the BSP’s and the 33/11kV substation. The arrangement has the disadvantage that a fault on the section from the tee point to the open point will interrupt supply to the transformer. Pole mounted ABSD near the tee point may be used if it can be justified on the balance of cost and IIP risk, see section 3.3.1.3.





Figure 3.24b shows a similar arrangement to 3.24a with the tee point at the 33/11kV substation. In this case motorised isolators (A1 and A2) are used to provide the open point. Both isolators are motorised for remote operation and during normal operation one will be open and one closed. Load transfer is possible by transferring the open point. This arrangement can be used as BSP interconnector when both isolators are closed. Figure 3.24c is a variation of 3.24b, where one circuit is cable connected and the other overhead line, providing auto reclose of the overhead line section of circuit. Feeder protection at one BSP’s will be required to detect faults through to the circuit breaker at the other, without operating for faults on the 11kV side of the transformer. Arrangements of figures 3.24a and 3.24b are suitable for cable connected circuits by replacing the fault thrower with pilot wire intertripping.

3.4.5 Rural 33kV Networks

3.4.5.1 Radial Networks

Rural networks are generally (not always) overhead line connected and the 33/11kV substation arrangements shown in figures 3.20, 3.22, 3.23 and 3.24 will apply in most instances. At rural locations with long distances between adjacent BSP’s the interconnection capability of figure 3.24 is likely to be severely limited by poor voltage regulation. Design of rural networks can be problematic due to low fault levels at the remote ends and poor voltage regulation. Low fault levels are particularly a problem where it is difficult to discriminate between a fault at a location remote from the BSP and an 11kV fault at a substation nearest the BSP. One particular problem area is a relatively high load density in a rural area remote from a BSP site. Although a pair of circuits may be dedicated to feed the substation a 24MVA load will almost certainly require 40MVA cable circuits and possibly special low impedance transformers. It is preferable to use 3 x 24MVA circuits with transformers paralleled on the 11kV busbar. The 11kV busbar fault level will normally be well within the 250MVA limit of the 11kV network. An alternative is to feed the area from two 33/11kV substations on three or more circuits.





A 33/11kV substation may be selected as a rural hub for future uprating to a BSP. Initially the substation can be supplied by 2 x 33kV cable circuits, or possible 2 x 132kV circuits running at 33kV feeding into a 33kV switchboard.

3.4.5.2 Ring Networks

Simple ring networks are advantageous where two or more 33/11kV substation may be supplied by two feeder circuits from the same BSP. Two transformer substations are connected into the 33kV network as shown in figure 3.23 but for a ring network the bus section circuit breaker is closed. Typical network arrangements are shown in figure 4.19 and 4.20a.

3.5 11KV SWITCHBOARD

11kV switchboard arrangements are the same as shown for 33kV switchboards as shown in figure 3.21. Care must be taken when designing large capacity 11kV substations (particularly high capacity 132/11kV) that all feeder circuits can be connected into the substation without excessive de-rating. Substations in urban areas, where most or all of the circuits are cable, may be prone to excessive de-rating of cables due to;

1. close proximity of other cables and 2. de-rating effects of laying cables deeper

Cable identification and repair is made increasingly difficult by laying cables at multiple depths in close proximity. Cable tunnels or trenches overcome some of the above problems but are easy targets for malicious acts and are not recommended.





4 NETWORK CONNECTIVITY

4.1 GENERAL INFORMATION

4.1.1 Overview

The arrangements shown in this section are provided to assist in designing the primary network for compliance with the design principles of section 2 and standard arrangements of section 3. Drawings are representative of connectivity and do not show all substation equipment. Extensions and modifications to the primary network should be designed with consideration for capital and revenue costs balanced against operational resilience. In general simple radial feeds are preferred unless a specific case can be made for more complex arrangements.

4.1.2 Flexibility

The ability to restore supplies during loss of main network circuits is determined by the availability of transfer capability. Speed of restoration is determined by the method of switching ranging from automated to local manual. On load transfer capability (ie without customer disconnection) is possible only where two adjacent networks are;

• of the same network voltage, • the same vector group, • the same phase rotation.

4.1.3 Cascade Tripping

Networks should be designed so that during normal operation and during planned outage conditions any unplanned trip event does not cause severe thermal overload of any part of the network or cause operation of any protection devices. In practical terms this means that during planned outages there must be the facility to re-arrange the network (where required) so that load is disconnected during an unplanned trip event. This is normally achieved by breaking circuit parallels and operating the network at single circuit risk. Although this appears to increase the risk to customer supplies for an





unplanned trip in reality it reduces the number of customers at risk per circuit and eliminates the risk of cascade tripping caused by severe overload (and eliminates the risk of damage to network assets).

4.1.4 Voltage Levels

With regard to network voltage levels Central Networks operate at the following voltage levels;

Table 5 - Network Voltages Network Voltage Function 132kV Sub Transmission / primary voltage 33kv and 66kV Primary voltage 6.6kV and 11kV HV Distribution 400V LV Distribution

In addition CN West operates with 11kV network vector groups of red phase at 0° (12 o’clock), +30º (1 o’clock), and -90º (9 o’clock) relative to the 132kV network Red phase. CN East operates with one 11kV vector group of 0° (12 o’clock).

4.1.5 Engineering Recommendation P18 – Complexity of 132kV Circuits

Although ER P18 is aimed to limit the complexity of 132kV circuits the principles are applicable to all primary voltage levels. ER P18 places three main restrictions on the design of the network.

1. The normal operating procedure or operating gear operation for making dead any 132kV circuit shall not require the opening of more than seven circuit breakers. These circuit breakers shall not be located on more than four different sites.

2. Not more than three transformers shall be banked together on any one circuit at any one site.

3. No item of equipment shall have isolating facilities on more than four different sites.





4.2 PREFERRED ARRANGEMENTS

4.2.1 Sub Transmission Networks

Prior to the introduction of the 275kV and 400kV networks the 132kV network was designed as a transmission network (National Grid) for interconnecting power stations and load centres. As new larger generating stations where introduced in the 1950’s and 1960’s feeding into the 275kV (and later the 400kV) ‘supergrid’ network Grid Supply Points (GSP’s) were introduced to feed into the 132kV network. In the early 1970’s the 132kV network became a sub transmission / distribution network and ownership transferred from the CEGB to local area electricity boards (forerunner of the DNO). At that time the 132kV network still included several small coal-fired generating stations, however, most if not all of these power stations have now closed. Embedded power stations connected to the 132kV network are now limited to a few gas fired stations constructed in the 1990’s and more recently large windfarms. The development of the 132kV network from a National Grid transmission network to a Sub Transmission / Distribution network has resulted in;

• 132kV double busbar substations (ex generating stations) in city locations now supplied from GSP’s up to 30km’s away. These substations are generally approaching the end of their useful life (1930’s construction). Replacement by double busbar substation is usually not appropriate for the requirements of the network,

• Interconnection of networks using a mesh substation, typically 4 switch closed mesh. Again this arrangement may not be appropriate for future networks and simplification of the arrangement should be considered when asset replacement is required.

There are many potential arrangements to replace the embedded double busbar or closed mesh substation arrangements with simplified protection schemes. Typical networks using standard substation arrangements for 132kv sub transmission networks are shown in the following examples. Figure 4.2a and 4.2b shows simpler alternatives for replacing an embedded double busbar arrangement of figure 4.1, and, figure 4.4 to 4.6 show alternatives for replacing a 4 switch mesh arrangement shown in figures 4.3a to 4.3c.





4.2.1.1 Replacement of Double Busbar Substation

Figure 4.1 – Existing 132kV Sub Transmission This arrangement exists where supplies to city demand centres were originally provided by local generation. BSP 1 would originally be a generation infeed substation with a 132kV double busbar switching station to provide supplies to BSP’s 2,3 and 4. To maintain supplies after closure of the generation station a new GSP and interconnecting 132kV circuits were constructed at a remote location. In most cases a double busbar arrangement is not required at BSP 1 substation and a more cost effective solution can be found when asset replacement is required. Typical alternative arrangements to be considered are shown in figures 4.2a and 4.2b.

Figure 4.1

GSP 132kvs/s

BSP 1 - 132kv s/s

Typically4 busbarsections

Up to4 busbarsections

Ex generatingstation

City Boundary

BSP 3

BSP 2

BSP 4





Figure 4.2a – Mesh Replacement for 132kV Sub Transmission In this arrangement the double busbar substation of figure 4.1 is replaced by 2 open mesh arrangements (auto isolation not shown). For loss of any two supply circuits from the GSP all BSP transformers will remain connected or will be re-connected after reclose sequence is complete.

Figure 4.2a





Figure 4.2b – Single Busbar Switching Arrangement for Sub Transmission This is an alternative to figure 4.2a. Although this arrangement increases the number of 132kV circuit breakers at BSP 1 it may be more cost effective due to simplification of protection and elimination of intertripping between the GSP and BSP1. It also has the advantage that a fault or planned switching between BSP1 and other BSP’s does not affect other circuits and interconnection between other GSP’s can be accommodated with capability of ‘on load’ transfer.

Figure 4.2b

GSP 132kvs/s


Towerline 1

Towerline 2

BSP 1

BSP 2

BSP 3

BSP 4

Cct 1

Cct 3

Cct 4

Cct 2

Towerline 3

Alternativesupply from

GSP 2





4.2.1.2 Replacement of Closed Mesh Substations

Figure 4.3a, 4.3b and 4.3c – Existing 132kV Closed Mesh Arrangements The networks shown in figure 4.3a and 4.3b are typical network arrangements with interconnection of circuits using a closed mesh arrangement. Figure 4.3a shows an arrangement with teed radial circuits and figure 4.3b shows a ring network. Many closed mesh substations are either over complex for the network requirements, and / or, at a point of interconnection between two GSP’s with the open point on the mesh corner isolator of the interconnecting circuit. Transfer capability is thus restricted to dead transfer by de-energising the mesh corner (including any circuit connected to that mesh corner), see figure 4.3c. In many cases the arrangement of figure 4.4 provides a more cost effective and flexible alternative.

Figure 4.3a





Figure 4.3b

GSP 132kvs/s


BSP 4

BSP 1

BSP 3

BSP 2

Cct 1

mc 1

mc 2mc 3

mc 4Cct 2

Cct 3

Cct 4

Figure 4.3c





Figure 4.4 – 132kV Interconnection Between GSP’s, Double Circuit Transfer In this arrangement BSP 2 has 2 circuit breakers normally run in the open position. GSP 1 supplies BSP 1 and BSP 2, GSP 2 supplies BSP 3. BSP 2 demand can be transferred to GSP 2 by opening the motorised isolator and closing the circuit breaker. This operation is simplified where transformer circuit breakers are installed at BSP 2. Also BSP 3 demand can be transferred to GSP 1 by closing the circuit breakers at BSP 2. Protection is simplified to standard transformer feeder protection. The circuit breakers used purely for on load switching only, feeder protection provided at the GSP circuit breakers. Where intertripping exists between any substations on the circuit between GSP 1 and 2 (eg, Network Rail connection) it will be necessary to install feeder protection at the open CB at BSP 2. The arrangement can also be used with four circuits from the same GSP source if required particularly if more BSP’s are connected. The in line circuit breakers providing a means of breaking the circuits (reducing the number of ends and addresses) for compliance with ER P18.

Figure 4.4





Figure 4.5 - 132kV Interconnection Between GSP’s, Single Circuit Transfer Method 1 This arrangement enables transfer of BSP 2 demand at single circuit risk. In this example the transfer is reliant on the circuit 1 to BSP 3 being available. Typically this connection is required when the demand of BSP 1 and BSP 2 exceeds 100MW for compliance with ER P2/6 (class D supply). Where the two source substations are from different GSP’s the interconnecter also provides GSP transfer capability.

Figure 4.5





Figure 4.6 - 132kV Interconnection Between GSP’s, Single Circuit Transfer Method 2 This is similar to 4.5 above, the single interconnecting circuit providing mutual second outage support to either network.

Figure 4.6

BSP2

SourceSubstation

1

BSP 1

M

M

BSP4

SourceSubstation

2

BSP 3

M

M





4.2.2 Radial Distribution Networks

Radial Networks are characterised as circuits from a source substation that terminate at the primary winding of one or more transformers. Terminating circuits with transformers provide three major advantages for detection of network faults,

1. Fault current on the lower voltage network is reduced on the higher voltage network in proportion to the transformer winding ratio,

2. The high impedance of a transformer winding relative to circuit impedance, and, 3. Dependant on transformer neutral earthing arrangements, earth fault current on the

lower voltage network produce phase – phase currents (not earth currents) on the higher voltage network.

Also as power normally flows from the higher voltage network to the lower voltage network a reversal can be detected to trip the transformer lower voltage circuit breaker. A further advantage is that protection equipment is segregated, there is no protection equipment associated with circuit 1 that will trip circuit 2. Representations of typical applications of radial networks are shown below (figures 4.7 to 4.18). Circuit breakers and isolators etc are not shown. Detailed substation arrangements are shown in section 3 (Substation Layouts). Figure 4.7 - Simple Single Feeder with Lower Voltage Backfeed. Normally employed at rural 66/11kV and 33/11kV substations where the 11kV network cannot maintain voltages within statutory limits. Where open points are manually operated the number of customers should be limited to 2,000 (4MVA). Up to 6,000 customers (12MVA) can be connected with this type of arrangement where backfeeds are automated.

Figure 4.7





Figure 4.8 Simple dual feed arrangement, used at all voltage levels.

Figure 4.8

Figure 4.9 – Double Circuit Radial Network More than one substation sharing feeder circuits. Can be utilised at all voltage levels but typically employed at 132kV in rural areas where the capacity of the circuits substantially exceeds the demand at each substation. Where total demand exceeds 100MW interconnection with other networks is required to meet the requirements of ER P2/6. Lower voltage interconnection between substations on the same higher voltage network can be utilised during transformer outages but not circuit outages. This example shows the maximum number of substations that can be connected within the limitations of ER P18.

Figure 4.9

SourceSubstation





Figure 4.10 – Double Circuit Radial Network with Tee Combination of arrangements 4.7 and 4.8 above. Typically employed at 66kV and 33kV.

Figure 4.10





Figure 4.11 – Three Transformer Substation Supplied From Same Source (GSP or BSP) This arrangement shows a transformation point with three circuits supplied from the same source. A three circuit supply provides higher transformer utilisation than an equivalent two circuit supply; each transformer can be loaded up to 67% nominal load compared to 50% with a two circuit feed. Actual firm capacity during first outage condition is dependant not only on the least rating condition of the remaining circuits supplying the demand but also their ability to share demand in proportion to their rating. 11kV busbar: For 132/11 or 33/11kV networks feeding an 11kV busbar: It is normal practice to operate with one transformer feeding an isolated section of busbar (created by open bus section switch) to reduce fault level within the rating of the 11kv network. The number of customers connected to the isolated section of busbar (single circuit feed) shall not exceed the limits stated in the design criteria of section 2 (Design Principles). 33kV busbar: Generally for 132/33kV networks feeding a 33kV busbar the fault rating of the switchgear is the limiting factor and is generally adequate to enable all three transformers to be paralleled. Where fault level exceeds the switchgear rating a reduction in fault level can be obtained by operating with one transformer on open standby. Typically the numbers of customers connected to the busbar at this voltage level will necessitate an automated changeover scheme to be employed for loss of a circuit.

Figure 4.11





Figure 4.12 - Three Transformer Substation Supplied From Diferrent Source (GSP or BSP) A variation of 4.11 above where the third circuit supplied from another source substation. In this example load sharing is likely to have more impact than in example 4.11

Single GSP supply source: Where the two source substations are connected to the same GSP it is preferable to operate the network with parallel supplies, ie, no open points.

This may not be possible due to fault level restrictions at the lower voltage switchboard, typically a problem at 11kV but may also be at 33kV or 66kV.

If parallel operation is planned network studies should be carried out to ensure that reverse power flows across transformers are not likely to occur in normal operation or during circuit outages. The tapchange control scheme may also need replacing.

Different GSP supply source: Where the source substations receive their supplies from different GSP’s it will be necessary to operate with an open point as reverse power flows are more likely to occur and are difficult to predict.

Where the transformers supply an 11kV network the open point will typically be at position 3 and the transformer supplied from Substation 2 and the 11kV network will be at single circuit risk for faults on the primary network.

Where the transformers supply a 33kVor 66kV network from the 132kV network the open point will typically be at position 2 and the transformer supplied from Substation 2 will be on open standby.

132kV networks supplied from GSP’s with 132kV Static VAR compensation, or other forms of capacitive switching installed, should not be operated with transformers energised and off load. In these circumstances the open point should be preferably be at position 3 leaving the transformer energised and on load. Care should be taken to ensure demands do not exceed the limit on customers at single circuit risk. Open points at position 1 (plus at points 2 or 3) are used occasionally to de-energise the transformer and reduce iron losses.





Figure 4.12

Figure 4.13 – 33/11kV Substations Supplied from Two BSP’s This arrangement normally applies to 33kV networks with transformation to 11kV.

This circuit arrangement has the advantage of providing transfer capability between source substations. During circuit outages at either source substation the demand at substation 3 can be transferred (on single circuit risk) if required to the other.

The arrangement also has a benefit that under fault outage conditions at one of the source substations demand naturally migrates to the other source due to changes in network impedance (the source substation with depleted infeed capability will have a higher than normal impedance).

The normal open point provides a means of feeding Substation 2 busbar from substation 1 (or vice versa) during emergencies.

Single GSP supply source:

Normally in this application the transformers would be paralleled on the lower voltage switchboard and no open point is required.

Different GSP supply source:

If the two supply sources are in different GSP groups the bus section switch on the lower voltage busbar can be opened (if required) to prevent excessive circulating currents or fault level.





Figure 4.13

Figure 4.14 - 33/11kV Substations Supplied from Two BSP’s (Double Circuit) This is a similar arrangement to 4.13 above but supplies 2 substations.

This is particularly useful at 33kV where a double circuit wood pole overhead line interconnects two BSP’s. Note: proximity work on one circuit of double circuit wood pole overhead line requires both circuits to be de-energised.

Figure 4.14

SourceSubstation

1

SourceSubstation

2

Substation3

Substation4

Normalopen points

Figures 4.15a and 4.15b – 11kV Network Infeed at a BSP Where transformation to 11kV is required at a BSP two methods may be employed to achieve this.

The arrangement shown in 4.15a uses a local 33/11kV substation supplied from the BSP 33kV switchboard.

The arrangement in 4.15b utilises the 132kv network to derive the 11kV supply by direct 132/11kv transformation.





Figure 4.15a The advantages of this arrangement are;

• 33/11kV transformer capacity can be flexible to meet the 11kv demand, ie, use of 7.5/15MVA or 12/24MVA units,

• Reduced installation costs of 33/11kv transformers compared with 132/11kV, • Typically there will be some means of transferring the 33/11kV substation to another

33kv feed during a double outage on the 132kV network feeding the BSP. • Two levels of voltage control between the 132kV network and the 11kV network.

Figure 4.15a

Figure 4.15b The advantages of this arrangement are;

• The use of 132/11kV transformation frees capacity on the 132/33kv transformers • Using the winter ratings of standard transformers, 90MVA at 132/33kv and 30MVA at

132/11kV, the aggregate firm (cyclic) rating of this arrangement is 156MVA and matches the winter maximum post fault rating of the majority of existing 132kv overhead lines (Lynx conductor - 160MVA).

Figure 4.15b

SourceSubstation

132/33kV

132/11kV

132/11kV





Figure 4.16 – Alternative arrangement to 2 x 132/11/11kV or 3 x 132/11kV Substation This is an alternative to either a three transformer substation with cross bay, or, a two 132/11/11kV transformer connection.

With respect to the former it enables firm supplies into the 11kV network. Typically a three transformer arrangement is operated with two transformers in parallel and one transformer connected to an isolated section of network to avoid overstressing.

With respect to the latter it removes the potential problem of voltage control due to load imbalance on the two secondary windings.

Figure 4.16





Figure 4.17 – Two 33/11kV Substations Supplied by 3 Circuits This arrangement is typically used on 33kV networks to supply 2 x 24MVA firm capacity 33/11kV substations.

The direct feeds are 24MVA circuits and the shared feed a 40MVA circuit. The arrangement can be utilised effectively to connect a new 33/11kv substation where a double circuit overhead line presently supplies a single substation.

Both 24MVA circuits should be connected to the same section of 33kV busbar at the source substation (ie, in a separate protection zone to the 40MVA circuit).

The resultant arrangement will allow proximity work to be carried out on the double circuit line with supplies maintained on the 40MVA circuit. Any potential shortfall in capacity if the aggregate substation maximum demand exceeds 40MVA can normally be resolved by transfers, timing of outage, or, generation.

Figure 4.17





Figure 4.18 – 33kV Tee Connections Rural radial connected network. Two ongoing circuits from one primary substation.

This type of network would normally be protected by HISET protection (main protection) and would be set to reach into the transformer at Primary 1.

This sets the reach of the HISET protection along the ongoing circuit and if the circuit impedance is high (long rural circuits) will not reach the transformers a Primary 2 or 3 (see section 6.3.2). The remaining section of circuit being protected on IDMT protection. IDMT protection is not acceptable as a circuit main protection and in such circumstances it will be necessary to use other types of protection.

Figure 4.18





4.2.3 Ring Networks

Ring networks are used for two types of network arrangement:

1. to feed multi-substation networks where circuit capacity is much greater than transformer capacity and several transformers can be connected to one circuit,

2. at single substation sites, using a cross bay arrangement, to provide a secure supply to three or more transformers at a single substation site when supplied from two circuits

4.2.3.1 Extension of multi-substation ring networks

Figure 4.19 below shows the preferred method of connecting a new substation into a ring network.

Figure 4.19 – Standard Ring Network

SourceSubstation Break into

existing circuit

SUB 1New Double Circuit

SubstationRing Connected

SUB 2New Double Circuit

SubstationRadially Connected

The preferred arrangement is to extend the ring through a mesh substation as shown for SUB 1. When extending the ring in this way the circuits to the new substation must be adequately rated to supply all remaining connected substations in the event of an unplanned outage at any point of the ring.





Teed circuits (SUB 2) terminated by transformers with no interconnection into other networks are permissible provided that;

1. no more than one tee per section of ring is connected (ie, one tee connection between two cross bay circuit breakers), and,

2. the main protection scheme will clear all faults within main protection clearance times (see section 2.14).

Where circuits are teed from ring circuits protected by distance schemes the remote ends of the tee section may not be fully protected within main protection fault clearance times as zone 2 reach is defined by the characteristics of the ring circuit and is set to reach 50% (by circuit impedance) into the following protection zone. The implications for protection of the tee section are that;

1. The impedance of long tee circuits may exceed the zone 2 setting leaving the remainder of the circuit with zone 3 clearance times. Zone 3 is regarded as back up protection only.

2. As there are two sources of fault current to the tee point the distance protection ‘appears’ to see the fault to be electrically at a further distance than it actually is and protection under reach occurs. Thus in the most severe cases sections that appear to be adequately protected with zone 2 clearance times will trip in zone 3 clearance times. Under reach at a point electrically mid way between the two sources of a simple ring will cause an under reach of 50% the impedance (and hence length) of the tee circuit.

Under reach is more problematic when the tee point is further away from the electrical midpoint of the ring network, thus circuits teed from the first section of a ring network are the most vulnerable to this effect. Rural 33kV Ring Network: Figure 4.20a shows an application for a 33kV rural ring network. Primary substations 3 and 4 form part of a ring network supplied from BSP 1. The ring between BSP 1 and BSP2 must contain an open point. The circuit to one transformer of Primary 2 is teed from the ring and the problems of under reach as discussed above may apply to the tee section. This can be overcome by applying zone 1 and zone 2 settings to the ring network and protecting the tee section with a PMAR with hi-set protection as shown in figure 4.20b Primary 1 has a single circuit supply and thus has restrictions on the number of customers connected.





Rural 33kv Ring Networks Figure 4.20a – Rural 33kV Ring Network

Figure 4.20b Rural 33kV Ring Network, Protection Issues for Tee Connection

4.2.3.2 Interconnection of multi-substation ring networks

A maximum of two ring networks may be interconnected to form a more complex ring provided that the interconnection is either;

1. A closed four switch mesh, or, 2. by a single or double circuit between two substations (one from each ring network)

provided that each interconnecting circuit has discrete protection with circuit breakers at either end.





Figures 4.21a, 4.21b and 4.21c show examples of interconnection using a 4 switch mesh, a double circuit and a single circuit respectively.

Figure 4.21a – 4 switch mesh interconnection

Figure 4.21b – double circuit

Figure 4.21c - single circuit

4.2.3.3 Single Substation Ring Network

Figure 4.22 shows the application of circuit breakers to create a secure mid point to the primary connection of three transformers. The principal can be extended for connection of more transformers if required. A practical limit is at the point when the rating of n-1 transformers exceeds that of n-1 circuits.

Figure 4.22 – Three Transformer Firm Connection from 2 Circuits





Connecting the third transformer in this way is relatively expensive in terms of protection. When compared to a radial network the double cross bay typically requires distance protection towards the supply source with accelerated intertripping and mesh corner protection and auto reclose. A further consideration is that a three (or more) transformer site may overstress the lower voltage switchboard and / or network requiring open points on the lower voltage switchboard (hence single circuit outage risk) to reduce fault levels. An alternative is to use four transformers in two pairs and remove the cross bay arrangement.





5 NETWORK EQUIPMENT

5.1 TRANSFORMERS

Transformers with 132kV primary windings shall comply with the ‘CN Grid Transformer Specification’, and will be CMR rated to the requirements of ENATS 35-3. Transformers with 66kV or 33kV primary windings shall comply with the ‘33/11.5kV and 66/11.5kV Transformer Technical Specification’, and will be CER rated to the requirements of ENATS 35-2.

5.1.1 Standard ratings and Impedances

Impedance has been selected on the basis of a two transformer substation (paralleled at the secondary winding) with maximum fault level applied to the primary winding terminal. With this arrangement the maximum fault level of the network connected to the transformer secondary will be within 95% of the network rating allowing for +/-10% tolerance during manufacture. The values of maximum primary fault levels used in the calculation (at the primary winding connection) are shown below.

• 132kV - 31.5kA • 66kV - 20.0kA • 33kV - 31.5kA

Note: In practice, fault levels at the primary winding connection are normally lower than the assumed values. This will provides some headroom for connection of generation, and in some cases paralleling of more than 2 transformers.





Table 6 - Standard Transformer Ratings and Impedances

% Impedance (tolerance of +/-10%) Voltage Ratio (kV)

Nameplate Rating (MVA)

On rating At 100MVA base

Notes

132/66 90 13.5 15.0 66kV network rated at 17.1kA

132/33 90 13.5 15.0 33kV network rated at 25kA


132/33 120 18.0 15.0 33kV network rated at 25kA


132/11 30 30.0 100.0 11kV network rated at 13.1kA (250MVA)

132/11/11 2 x 30 18.0 (primary winding) 9.0 (secondary winding)

60.0 primary 30.0 secondary

When paralleled across 2 transformers (one secondary winding each). 11kV network rated at 13.1kA (250MVA)

66/11.5/11.5 TBC TBC TBC 11kV network rated at 13.1kA (250MVA)

66/11.5 40 TBC TBC 11kV network rated at 13.1kA (250MVA)

33/11.5 40 35.0 87.5 11kV network rated at 13.1kA (250MVA)


33/11.5 24 17.0 70.8 Low impedance unit for use where 33kV fault level low


Note: the above table is based on all 11kv networks having a minimum fault capacity of 250MVA. Items in bold are preferred sizes.





5.1.2 Tapping range

Standard tapping ranges are:

Table 7 – Tapchange Range

Voltage Tap Range Tap Positions

Range per tap

Notes

132/66 -20% to +10% 19 1.67%

132/33 -20% to +10% 19 1.67% 132/11/11 -20% to +10% 19 1.67%

132/11 -20% to +10% 19 1.67% 66/11.5 -17.16% to

+5.72% 17 1.43%

66/11.5/11.5 -20%+10% 19 1.67%

33/11.5 -10% to +10% 17 1.25% 1 Notes:

1. On circuits where target busbar volts cannot be achieved using the standard tapping range it is permissible to use a tap range of -17.16% and +5.72% (17 tap positions of 1.43%).

5.1.3 Vector Group

The standard transformer arrangement for 132/66kV and 132/33kV transformers is the STAR / delta (Yd) connection. The standard 132/11kV arrangement in CN East is STAR / star, STAR / star and STAR / delta configurations apply in CN West. The standard 33/11.5kV arrangement is DELTA / star. The vector group of a transformer is determined by the relative phase relationship of the high voltage and low voltage networks to be interconnected by the transformer. Generally

• Star / delta transformers with HV bushing connections require links for YD1 or Yd11 connection

• Delta / star transformers with HV bushing connections require links for Dy1 or Dy11 connection

• 132/11kV transformers in CN East region are all Yy0 (with the exception of Burnaston BSP that is Yd)





• 132/11kV transformers in CN West may be either Yy or Yd connected dependant on location (see CN West LTDS)

5.1.4 Standard Connections

Arrangements are based on the transformer connection methods shown in Table 8.

Table 8 – Transformer Connections

Primary Voltage (kV)

Secondary Voltage (kV)

Primary Connection Secondary Connection

132 66 Bushing Bushing

132 33 Bushing Cable Box 132 11 Bushing Cable Box

66 11.5 Bushing Cable Box 33 11.5 Cable Box Cable Box

5.2 OVERHEAD LINES

5.2.1 132kV Network

New Installations: New build double circuit 132kV overhead lines shall be constructed to ENATS 43/7 ‘132kV Steel Tower Transmission Lines Specification L4(M) with UPAS (300mm2 AAAC) phase conductors sagged for 75 °C operation. Where higher circuit ratings are required heavy duty double circuit 132kV overhead lines shall be constructed to ENATS 43/9 ‘132kV Steel Tower Transmission Lines Specification L7(C) , with RUBUS (500mm2 AAAC) phase conductors sagged for 75 °C operation. Single circuit 132kV overhead lines may be used to provide a third circuit into a network where the group demand exceeds 100MW for compliance with ER P2/6 (class D supply groups). A wood or steel pole construction conforming to ENATS 43-50 is acceptable for this application providing the general overhead line design type and the detailed installation design (span lengths, pole sizes etc) are approved by CN. Conductor type to be used may be either UPAS or POPLAR (200mm2 AAAC) depending on required circuit capacity.





Rise of earth potential at the base of metallic supports, or cable sheath of any underground cable, must comply with BSEN 50341 clause 6.2.4. Where un-earthed single circuit wood pole overhead lines are used care is required to ensure that substation rise of earth potential does not exceed 650V under all operating conditions. Re-conductoring: When re-conductoring any circuit the replacement conductor should be sagged to provide the maximum thermal rating of the conductor type within the constraints of the overhead line design (tower design, condition etc). When re-conductoring existing overhead lines where the existing phase conductors are single Lynx the feasibility of replacing with UPAS should be considered. When re-conductoring existing overhead lines where the existing phase conductors are twin Lynx, Zebra or Finch the feasibility of replacing with RUBUS should be considered. Circuit ratings are shown in the Table 9 below:

Table 9 – Overhead Line Ratings

Conductor Type / size

Pre fault rating (MVA)

Post fault 24 hour rating (MVA)

P27 rating (MVA)

Conductor temp °C

50 65 75 50 65 75 50 65 75

Season

Lynx / 175 mm2 ACSR

Winter 111 126 134 132 150 160 118 134 143

Spring / Autumn

103 119 128 123 142 153 110 127 137

Summer 89 108 118 106 128 141 95 115 126 Zebra / 400 mm2 ACSR

Winter 191 216 231 227 257 275 203 230 246

Spring / Autumn

178 205 221 211 244 263 189 218 235

Summer 154 186 204 183 221 243 164 198 217





Table 9 – Overhead Line Ratings (continued)

Conductor Type / size

Pre fault rating (MVA)

Post fault 24 hour rating (MVA)

P27 rating (MVA)

Conductor temp °C

50 65 75 50 65 75 50 65 75

Season

POPLAR / 200 mm2 AAAC

Winter 120 137 146 143 163 174 128 145 155

Spring / Autumn

112 129 140 133 154 166 119 138 149

Summer 97 117 129 115 139 153 103 125 137

UPAS / 300 mm2 AAAC

Winter 159 180 193 189 214 230 169 192 205

Spring / Autumn

147 171 185 176 203 220 157 182 196

Summer 128 155 170 152 184 203 136 165 181 RUBUS / 500 mm2 AAAC

Winter 218 247 265 259 294 316 232 263 282

Spring / Autumn

203 235 254 241 280 302 216 250 270

Summer 175 213 234 209 253 279 186 227 249

Notes:

• Post Fault ratings may be applied for up to 24 hours provided that circuit loadings were initially below the pre fault ratings (84% of post fault rating)

• Post fault ratings are based on 12% exceedence, P27 ratings are based on 3% exceedence

• P27 ratings are reduced to 96% based on feeding city or industrial loads

• All ratings are based on supplying demand with a minimum of 2 circuits, for single circuit supplies (eg a non firm customer supply) the level of permitted exceedence reduces to 0% with subsequent reductions in ratings.

• AAAC conductor ratings based on L2 type aluminium alloy

• Wind Speed 0.5 metres / second, solar radiation = 0





• Seasons are

o Summer - May / June / July / August, ambient temperature 20 °C

o Spring / Autumn - March / April / September / October / November, ambient temperature 9 °C

o Winter - December / January / February, ambient temperature 2 °C

• Ratings above calculated using EATL Spreadsheet OHRAT2 using the cyclic loadings below (based on ACE Report 104, Figure G5).

demand at or above

(% of Imax)

Input

100 0.00

95 0.25

90 0.84

85 2.19

80 4.98

75 11.0

70 20.0

65 33.0

60 47.0

55 61.0

50 79.0

45 89.0

40 97.0

35 100.0

30 100

25 100

20 100

15 100

10 100

5 100

0 100

5.2.2 66kV Network

Under Preparation

5.2.3 33kV Network

See section 3.4.2 of the Network Design Manual





5.3 UNDERGROUND CABLES

5.3.1 132kV

Most 132kV cables are installed on circuits that are predominately overhead to prevent a ‘wirescape’ where all the circuits meet at GSP’s, or, relatively short underground cable sections crossing development areas. For these applications cable ratings shall not be less than the maximum rating of the associated overhead line system for all seasons of summer, spring / autumn and winter for all conditions of pre and post fault and P27. The overhead line system rating being defined as the maximum thermal rating that can be applied to the existing conductor type (normally 75 °C). All cables must have sufficient thermal independence to be fully loaded simultaneously. Where a BSP, or group of BSP’s, are to be supplied by cable circuit only the rating of the circuit will be determined by the initial and future anticipated demand. Consideration should be given to the benefits of providing a cable with a higher rating than initially required to facilitate future developments and provide enhanced emergency performance against the marginal cost increase bearing in mind the relatively high cost of excavation compared to cable cost. For the purposes of calculating cycle rating the load curve defined in section 5.2.1 should be used. In any event the minimum conductor size shall be 400 mm2 (copper conductor, XLPE insulation).

5.3.2 66kV

Under Preparation

5.3.3 33kV

See section 3.4.1 of the Network Design Manual





5.4 SWITCHGEAR

5.4.1 Specifications

Switchgear shall comply with the following Central Networks specifications;

• 132kV and 66kV Outdoor Circuit Breakers Technical Specification, • 132kV and 66kV Disconnectors, Earthing Switches, and Fault Throwing Switches

Specification • 33kV Indoor Metal Enclosed Technical Specification • 11kV Indoor Metal Enclosed Technical Specification

It is generally preferred that all switchgear shall be ENA approved, if not ENA approved the switchgear type must be approved by CN Network Engineering. 66kV and 132kV switchgear shall comply with ENATS 41-37 33kV and 11kV switchgear shall comply with ENATS 41-36 Substation switchgear arrangements using air insulated busbars and overhead connected open terminal switchgear is preferred at 132kv and 66kV although cable connected indoor GIS switchgear is permissible when constrained by limitations of space or if a necessity to obtain planning consents. All 33kV and 11kV substation switchgear shall be metal enclosed cable connected.

5.4.2 Switchgear Ratings

Minimum thermal ratings: are shown in Table 10.

Table 10 – Switchgear Minimum Ratings

132kV 66kV 33kV 11kV (40MVA transformer)

11kV (24MVA transformer)

Busbar 2000A 2000A 2000A 2000A 1250A Transformer Incomers 2000A 2000A 2000A 2000A 1250A Bus section 2000A 2000A 2000A 2000A 1250A Feeders 2000A 1250A 1250A 630A 630A

Notes:





• For 33kV switchboards at least one feeder switch per section of busbar shall be of the same rating as the busbar (a minimum of 2000A) for possible future use as a switchboard interconnector.

• 66kV and 33kV circuit breakers shall have a minimum 3 phase symmetrical and single phase fault breaking capacity of 31.5kA. This should be increased to 40kA where the X/R ratio exceeds 18.85 (DC time constant of 60mS).

• 132kV circuit breakers shall have a minimum 3 phase symmetrical fault breaking capacity of 31.5kA and single phase break capacity of 40kA. The 3 phase break capacity shall be increased to 40kA where the X/R ratio exceeds 18.85 (DC time constant of 60mS).

• 11kV circuit breakers shall have a minimum 3 phase symmetrical and single phase fault breaking capacity of 25kA.

Unless otherwise stated, fault ratings are 3 second ratings based on an X/R ratio of 18.85 (60mS DC time constant). For further details refer to Network Design Manual section 3.3.4.2





6 GUIDANCE NOTES

6.1 ENGINEERING RECOMMENDATION P2/6

The application of ER P2/6 with regard to ‘Class of Supply’ and its application to the network has been the cause of some confusion.

6.1.1 Class of Supply

Distribution networks are classified in ranges of group demand in table 1 of ER P2/6 as follows

Class Group Demand A Up to 1MW B 1MW to 12MW C 12MW to 60MW D 60MW to 300MW E 300MW to 1500MW

The class of supply determines the restoration requirements under first and second outage conditions. For each increase in classification level security of supply requirements become more onerous and increasing levels of investment are required for compliance.

6.1.2 Group Demand

Group Demand is defined as: For a single site: The appropriate estimated maximum demand given in the adopted load estimates or the Area Board’s own estimates for those points for which no load estimates have been adopted. For multiple Sites: The sum of the appropriate estimated maximum demands in the adopted load estimates with allowance for diversity appropriate to the Group, or the Area Board’s own estimates for those parts of the system for which no load estimates have been adopted.





6.1.2.1 Interpretation of Group Demand

Area Board’s are now Distribution Network Operators (DNO’s) The definition of group demand refers to load estimates that where adopted by the Electricity Council pre privatisation. The practice of adoption ceased on privatisation and load estimates are not adopted by any external organisation. The actual and forecast maximum demands published by the DNO’s in their ‘Long Term Development Statement’ should be used for ER P2/6 purposes.

6.1.3 Typical Network Arrangements

Sections 6.1.4 and 6.1.5 provide general guidance and shows typical network arrangements for the classes of supply B to E. Figure 6.1 relates to first outage requirements and figure 6.2 to second outage.

6.1.4 First Outage Requirements

BSP A feeds 3 primary substations, A1, A2 and A3. The group demand at primary A1 is less than 12MW and falls into class B requiring just a single circuit supply with transfer capability to restore supplies within 3 hours (the example shows 11kV load transfer to primary A3 by manual switching). The demand on primary A2 falls into class C but it is still acceptable to supply the group with a single circuit, however, class C groups have a more stringent requirement for supply restoration. For a first outage condition restoration of group demand less 12MW or two thirds group demand (whichever is smaller) must be restored within 15 minutes. This would normally be achieved by telecontrol switching of a 33kv circuit (in the example transfer at 33kv to BSP D). Any shortfall must be restored within 3 hours. Normally the 33kv backfeed will restore all supplies but if not this requirement may be met by manual switching (in the example transfer capability at 11kV from primary A3). The group demand at primary A3 also falls into class C. Substations sites for this application would typically have 2 x 24MVA or 2 x 40MVA, 33/11kV, transformers with supplies paralleled at the 11kV busbar by bus section switch.





BSP B shows a typical 132kV feed arrangement to a Class C supply group. This would be a relatively small BSP with group demand between 12MW and 60MW. Substations sites for this application would typically have 2 x 30MVA, 132/11kV transformers or 2 x 60MVA, 132/33kV, transformers with supplies paralleled at the 11kV or 33kV busbar (as appropriate) by bus section switch. BSP C shows a typical 132kV feed arrangement to a Class D supply group (group demand 60MW to 300MW) with a group demand up to 100MW. BSP D shows a larger Class D supply group with a group demand exceeding 100MW.

Figure 6.1





6.1.5 Second Outage Requirements

All the primary substations supplied from BSP A have no requirement to maintain supplies during second outages. The BSP itself does benefit with the 33kv interconnection to BSP D. BSP B group demand is less than 100MW so again no requirement to maintain supplies during second outages. BSP C group demand is also less than 100MW so again no requirement to maintain supplies during second outages. The interconnector provides support to BSP D. BSP D group demand exceeds 100MW thus a third circuit is required to restore supplies. For group demand between 100MW and 150MW restoration of GD less 100MW must be restored within 3 hours, for group demand between 150MW and 300MW restoration of one third of GD must be restored within 3 hours.





The entire supply group falls into Class E of ER P2/6 and all consumers must remain connected for a double outage. Thus a minimum of 3 permanently connected circuits are required to supply such a supply group.

Figure 6.2

Single feed 33kV networkClass B

No second outagerequirement

Open point -manual close

(3hrs)

NGT 275kV or 400kV

132kV

33kV

11kV

Single feed 33kV networkClass C

Group demand 12-60MWbackfed at 33kV


Open point -remote close

(15mins)

Second Outage Requirements

Double feed 132kV networkClass D

Group demand 60-300MWfor group demand <100MW


Double feed 132kV networkClass C

Group demand 12-60MWNo second outage

requirement Double feed 33kV networkClass C

Group demand 12-60MWNo second outage

requirement

Double feed 132kV networkClass D

Group demand 60-300MWfor group demand between 100MW and 150MW

restoration of GD less 100MWfor group demand between 150MW and 300MW

restoration of one third of GD(restoration required within 3 hours)

Double feed NGT networkClass E

Group demand >300MW(immediate restoration >2

fully rated infeeds)

Open point -manual close

(3hrs)

Open point - manualclose (3hrs)

BSP A

BSP B

BSP C

BSP D

PrimaryA1

PrimaryA3

PrimaryA2





6.1.6 Interpretation of Multiple Sites

The definition for multiple sites provided in ER P2/6 is too vague and taken to the extreme would result in all parts of the network falling under the requirements of a class E supply. How ER P2/6 is interpreted has the highest impact for double outage conditions between supply classes C, D and E. Central Networks interpretation of the application of ER P2/6 to multiple sites is to categories network supplies to substations as one of the following:

1. independent supplies 2. interdependent supplies 3. shared supplies

6.1.6.1 Independent Supplies

Supplies to substation sites are defined as independent when the loss of the two most critical supplies materially reduces supply capacity at one substation site only. Where a substation site is supplied by two main supply circuits a double outage will result in loss of supplies to that site, and, where interconnection exists, a reduction in transfer capability to adjacent sites. Reduction in transfer capability through loss of interconnection, is only regarded as ‘material’ if it results in none compliance with ER P2/6 at any adjacent substation site. Figure 6.3 shows an example of independent supplies. In this example all four BSP’s have a group demand below 100MW, however, the total group demand for the area supplied exceeds 100MW and could possibly exceed 300MW. In these circumstances the four BSP’s and their supply networks can be classed as independent. The class of supply at each site being determined by the total demand at that site.





Figure 6.3 – Independent Supplies

132kV

BSP A

BSP B

BSP CBSP D

GSP B GSP A

GSP D

GSP C

6.1.6.2 Interdependent Supplies

Supplies to substation sites are defined as interdependent when the loss of the two most critical supplies to one substation site reduces transfer capability of adjacent substation sites. In figure 6.4 all four BSP’s have group demands in excess of 100MW. GSP A normally supplies BSP A by a double circuit network connection; similarly GSP B normally supplies BSP B by double circuit network connection. However for a group demand in excess of 100MW there is a requirement to restore supplies (as stated in table 1 of ER P2/6) within 3 hours. The interconnector between BSP A and BSP B provides transfer capability to both sites. It should be noted that for class D supplies there is no requirement to restore supplies to all customers (group demand) other than in the ‘time to restore arranged outage’. Also, an interconnector between two GSP’s would normally be operated with an open point to avoid parallels across the two supply groups. A double circuit outage between GSP A and BSP A results in the loss of transfer capability to BSP B and thus reduces security at BSP B. Hence supplies to BSP A and BSP B are interdependent.





Supplies to BSP C and BSP D are essentially the same as the above example with the exception that both BSP’s are supplied from the same GSP. In this case it is unnecessary to operate the network with an open point on the interconnector circuit.

Figure 6.4 – Interdependant Supplies

Although supplies to each substation are interdependent the risk at each site can be managed so that the risk of losing supplies to both sites is minimal. Groups of interdependent circuits should be identified and planned outages restricted to one critical circuit at a time.





6.1.6.3 Shared Supplies

Where more than one substation site shares a supply network then the class of the shared section of the network is defined as the total demand from the source of supply up to the tee point. In figure 6.5 BSP A and BSP B have group demands that fall into class C and thus in isolation a double circuit to each BSP is adequate. In this example the total group demand on the two circuits from GSP A to the tee point exceeds 100MW and is thus a class D supply. Any transfer capability between BSP A and BSP B has no benefit as supplies to both BSP’s are lost for a double outage. The example of BSP C and BSP D is similar except that BSP C is a class D substation and the combined demand on the circuits between GSP C and the tee point exceeds 300MW (class E).

Figure 6.5 – Shared Supplies





Both cases fail to meet the ER P2/6 standard. If circuit capacities allow it would be simple to achieve compliance by installing a single circuit interconnector between BSP A and BSP D to form an interdependent network as shown in figure 6.6.

Figure 6.6 – Use of Interconnector for P2/6 Compliance

BSP A can be supplied from BSP D during a double outage of the circuits from GSP A, (supplies to BSP B would be lost). BSP D can be supplied from BSP A during a double outage of the circuits from GSP C, and, BSP C can be supplied by the single circuit from GSP B. Due to the interdependence of the circuits in this example not more than one planned outage is allowed at any time on any of,

• the two circuits from GSP A, • the two circuits from GSP C, • the single circuit from GSP B to BSP C, and, • the interconnector between BSP A and BSP D.





Another example of a shared supply is shown in figure 6.7. This is a ring network typically used for 132/11kV distribution. In this example the aggregate group demand, after diversity, of all the BSP’s results in a class D group demand on the two circuits feeding the network from GSP A. The circuit from GSP C to BSP C, normally operated with an open point, providing a third feed into the network.

Figure 6.7 - Ring Network

132kV

BSP A

BSP B

BSP C

BSP D

GSP A

GSP C

Class D

Again restrictions on planned outages apply, no more than one planned outage should be allowed at any time on the two main circuits from GSP A and the interconnector from GSP C.

6.2 FIRM CAPACITY

The interpretations above describe how substation sites and the networks feeding them are classified. This section deals with the ability of the network to meet requirements during outages. The ability of a substation site (or circuit) to comply with the ER P2/6 security standard is dependant on the demand restored, relative to group demand, within the time limit requirements of the class of supply.





Where a parallel connected network is used to feed a substation site an unplanned outage of any one circuit may result in the overload of components of the remaining circuits. This is acceptable provided the designed overload capability of that network component is not exceeded. Generally transformer and cable ratings include overload capability in their rating data. It is acceptable for an overload condition, due to a fault outage, to create a small amount of accelerated insulation ageing and therefore reduce the potential life of the asset. However, network components with low thermal inertia (joints etc) are prone to sudden failure and result in further unplanned circuit outages and loss of supplies to customers. Also excessive transformer overloads may result in an over temperature trip condition. If a potential overload condition does exist, and transfer capability is relied upon to reduce demand following the unplanned outage, the transfer must be completed within the designated short time overload capability of the remaining circuit components. Generation contribution factors are determined by table 2 of ER P2/6. Only generation that has the capability of remaining connected during the fault period, or, can be reconnected at declared export capability within the required timescales defined in the table 1 of ER P2/6 for the class of supply, shall be considered as contributing to security of supply. Great care should be taken when relying on generation to meet the requirements of P2/6. Generation output can be depleted without notice at any time leaving the network in a state of none compliance. Replacement network capacity could typically take up to a year to install where additional transformer capacity is required and several years for additional overhead circuit capacity.

6.2.1 First Outage

The most onerous first outage event is an unplanned fault outage. Firm capacity is the remaining capacity at a substation site (or circuits) after the loss of the most critical circuit. Remaining capacity includes;

• the capacity of any remaining feeder circuits, and, • transfer capability, and, • generation contribution

Substation sites with group demand up to 60MVA (class C) have no requirement to immediately restore supplies during first outage, however, in practice most substations with demands in excess of 12MVA will have duplicate infeeds.





Table 1 of ER P2/6 states that for a class D supply ‘a loss of supply not exceeding 60 seconds is considered as an immediate restoration’. Designing a network using this criterion can result in up to 300MW of demand reliant on a single circuit feed. Assuming an average demand per customer of 2kW any short term interruption could affect up to 150,000 customers. This level of customer service is deemed unacceptable. The maximum numbers of customers supplied at single circuit risk is stated in section 2.2 (Table 3) of this manual.

6.2.2 Second Outage

The most onerous second outage event considered is an unplanned fault outage during a planned outage. Second outages based on two concurrent unplanned outages are NOT considered. Group demand must exceed 100MW before there is a P2/6 requirement to restore supplies. Firm capacity is the remaining capacity at a substation site (or circuits) after the loss of the two most critical circuits. Remaining capacity includes;

• the capacity of any remaining feeder circuits, and, • pre fault transfer capability, and, • post fault transfer capability, and, • generation contribution





6.3 PROTECTION ISSUES

6.3.1 Pitfalls with multi-substation ring networks

The arrangement of figure 6.8 and 6.9 below shows some of the problems that can occur when extending ring networks. Due to the potential risk to customers connected to complex ring networks the only acceptable arrangements are the ring circuits shown in figure 4.19, 4.20a and interconnected rings as shown in figures 4.21a, 4.21b and 4.21c. The standard protection scheme for a ring network is distance protection, this may be enhanced for 132kV networks by accelerated intertripping to maintain zone 1 protection times to all parts of the network. All networks using distance protection as the main protection scheme must clear faults within a minimum of zone 2 protection times. Zone 3 shall not be used for main protection schemes at any part of the network. Teed connections from ring networks are prone to the following problems when using distance protection. Under reach: Figure 6.8 shows a tee connection between two substations of a ring network. Zone 1 distance protection settings for both SUB 1 and SUB 2 are defined at 80% of the circuit impedance between the substations, ie, SUB 1 zone 1 reaches 80% into the circuit to SUB 2 and SUB 2 zone 1 reaches 80% into the circuit to SUB1. Zone 2 is normally set to reach 50% into the next zone. This defines the maximum reaches of zone 1 and zone 2 protection along the teed circuit from both SUB 1 and SUB 2 and will be different depending on the relative position of the tee point. The maximum reach along the tee circuit is only obtainable when supplied from one or other of SUB 1 or SUB 2. Under normal conditions the tee point will be supplied from both ends of the circuit, ie, from SUB 1 and SUB 2. When supplied from both points fault current is shared and volt drop across the ring reduced, thus the distance protection at both SUB 1 and SUB 2 receive a higher voltage reference and lower current reference for the fault and hence the fault position appears to be further away.





This moves the demarcation of cover between zones 1 and 2 and more importantly between zones 2 and 3. Figure 6.9 shows this effect between zones 1 and 2 with a definite zone 1 section (blue) a definite zone 2 section (red) and a section that can be either (green).

Figure 6.8 – Distance Protection Under Reach

SUB 1 SUB 2

SUB 3

Sub 2, Zone 1 -Under reach

Sub 2, Zone 1 -Single circuit feed

Sub 2, Zone 180% cover Sub 1, Zone 1

80% cover

Sub 1, Zone 1 -Single circuit feed

Sub 1, Zone 1 -Under reach

Supply 1 Supply 2

Zone 1

Zone 2

Either Zone 1 or 2 Zone 3 Main Protection Zones: Figure 6.9 shows a ring network protected by distance protection where the limit of zone 2 reach of SUB 1 is to 50% between SUB 2 and SUB 3. Zone 1 of SUB 2 will reach 80% into the circuit towards SUB 3 thus providing a 20% error margin against zone 1 reach beyond SUB 3 and a 30% error margin between SUB 2 main protection and SUB 1 Zone 2 back up protection (on the circuit between SUB 2 and SUB 3). This sets the maximum zone 2 reach for SUB 1 along the tee section to SUB 4. In some instances zone 2 reach falls short of the end of the circuit. Also due to the under reach problem described above the zone 2 reach will vary in practice. When supplied from a single source (either SUB 1 or SUB 2) the whole of the tee circuit may be protected in zone 2 times, but when supplied from both substations the furthest section from the tee point may appear to both SUB 1 and SUB 2 protection schemes as a zone 3 fault. Where this occurs the tee connection point should be made at the nearest substation and the ongoing circuit connected through a circuit breaker, or the ring extended to loop through the substation as shown in figure 4.19, section 4.2.3.1.





Figure 6.9 – Distance Protection Under Reach on Long Tee Sections

6.3.2 Protection issues with teed rural networks

Figure 6.10 shows a 33kV radial network with hi-set used for main circuit protection. The hi-set reach is set to cover the transformer HV winding at primary 1. This defines the reach for the ongoing circuit to primary 2. For long feeders the impedance of the ongoing circuit is relatively high and may exceed the primary 1 transformer HV winding impedance leaving a section of the circuit covered only by the IDMT back up protection. Rural networks are particularly susceptible to this problem where there are many small capacity substations on multiple teed circuits.

Figure 6.10 – High Set Protection with Teed Feeders





6.4 RING NETWORKS

The arrangement in figure 6.11 below shows a multi-substation application that serves the same function as the radial equivalent in figure 6.12. Ring Network

Figure 6.11

Equivalent Radial Network

Figure 6.12





Some features of the each design are shown in Table 11 below:

Table 11 – Features of Ring and Radial Networks

Condition Feature

Ring Radial

Single circuit outage (fault)

One transformer at each end of circuit disconnected initially but auto restored.

One transformer from each substation disconnected. All network now at single circuit risk.

Double circuit outage (fault during planned outage)

The worst case scenario is a planned outage on one of the circuits from the source substation and a fault on the second circuit from the source. In all other cases some supplies are maintained, at best just one substation being disconnected.

All supplies disconnected.

Complexity (ER P18) No P18 issues, the ring can be extended within the limits of thermal rating and voltage regulation.

A maximum of two teed circuits are allowed on a circuit between source substation and remote substation to comply with ER P18 maximum addresses rule (maximum of 4 addresses).

Susceptibility to Human Error

Circuits that are under outage contain active protection equipment. Error can result in loss of supplies to customers

Circuits protection is generally independent.

Voltage regulation An outage of one of the first sections of circuit from the supply source into the network results in all of the network demand supplied from the other. This not only increases the demand on each section of circuit but also the distance from source substation to the last BSP on the ring and may result in excessive voltage regulation.

A single outage increases demand on the remaining circuit and load doubling, thus increased volt drop in the circuits. Although the effective circuit length does not change the number of paralleled transformers in service at each substation is reduced (typically by 50%, 2 transformer substation). Thus voltage regulation is likely to be no better than the equivalent ring network.





Table 11 – Features of Ring and Radial Networks (Continued)

Condition Feature

Ring Radial

Flexibility (Overhead line circuits)

Ring connection possible at any point but expensive heavy duty (DJT) tower required to achieve this.

Tee off available at any point of main circuit route. (may need tower replacement from suspension to tension tower).

Flexibility (cable circuits) Feasible to construct with single circuits between substations to form a ring.

Tends to require double circuit connections to the main feeder circuit.

Tee / ring point into substation (overhead connection)

Ring connection may be possible by overhead connection, conversely may require cable for both circuits depending on relative position of substation and main circuit connection point

Generally requires cable for one circuit. Other with overhead connection

Costs – Circuits All circuits must be sufficiently rated to supply several substations (very expensive).

Smaller conductor size possible on tee circuits compared with main route.

Costs – Main plant Cross bay of 2 x isolators and 1 x circuit breaker required at each site, thus increased costs (very expensive).

No cross bay costs

Costs – Protection Distance protection and mesh corner protection with auto reclose required for each feeder circuit due to cross bay. Possible additional cable and sealing end costs if cross bay cannot be established by simple overhead connection.

High voltage network protected by low cost DOC scheme at transformation points.

The main advantages of ring networks are;

1. circuits and transformers are independent and a circuit fault does not result in a permanent outage of its associated transformer(s).

2. a circuit fault tends to deplete security less than an equivalent radial network





3. secure mid point transformer connections can be made available from two supply circuits (ie for 3 transformer substation)

4. This arrangement can be achieved with single circuit supplies with direct routes between substations

However, there are several disadvantages;

1. Cross Bay costs are relatively high 2. there is a greater risk of human error during protection testing / maintenance as active

components of one protection zone are physically connected into an adjacent zone. 3. network extension connections are generally not as flexible as radial equivalents 4. extension to the ring require circuits ratings capable of supplying several substations

rather than being rated just for the new substation being connected. 5. Loss of the first circuit from the source may result in poor voltage regulation for the last

substation connected. For a substation near the supply source on a ring network the distance from supply source around the ring could be almost twice that of the furthest substation of an equivalent radial network.

6.5 PRIMARY NETWORK DESIGN

6.5.1 Transformer Replacement

Table 6 of section 5.1.1 shows the standard transformer voltage ratio’s, ratings and impedances for new transformers. The units in bold are preferred standard sizes and impedances. The transformer impedance values are designed to ensure the fault level of the associated lower voltage network does not exceed 95% of the LV network fault rating based on a 3 second fault rating of;

• 20kA at 66kV • 25kA at 33kV • 13.1kA at 11kV

In most instances the LV network fault level will be much lower than the values stated above. However, there are existing assets on the network that have much lower fault ratings, for example some 33kV switchgear at primary substations have a fault rating as low as 13.1kA. Normally the fault level will decay sufficiently not to affect embedded assets but this must be checked during network analysis.





Where replacement by the preferred standard transformer results in a fault level that exceeds 95% of the lower voltage network asset fault rating the high impedance equivalent unit should be used (where available). If the use of a higher impedance unit still results in excessive fault level the LV assets affected should be replaced and the preferred standard transformer used. Where replacement by the preferred standard transformer results in the inability to provide the LV busbar target voltage under all normal operating conditions (first outage and second outage where appropriate) with the transformer operated at its maximum thermal rating (peak demand for a cyclic load) a lower impedance standard transformer, or, a transformer with an extended tapping range, or both, may be used (where available).

6.5.2 132/33kV, 120MVA transformers

132/33kV, 120MVA transformers are not as cost effective as 90MVA units, and, they suffer from the disadvantage of placing a large number of customers at risk during outages. Also, the incoming 33kV circuit breaker and cable tails must be rated at 2730A to obtain full cyclic capacity from the transformer (33kV switchgear incomers are typically 2000A rated). Thus, 120MVA units should only be used where a case can be made on economic grounds and where it is impracticable to obtain the required firm rating using smaller units.

6.5.3 Transformers with Dual Secondary Windings (132/11/11kV or 66/11/11kV)

132/11/11kV, 2 x 30MVA transformer arrangements suffer from four main disadvantages (in addition to other disadvantages of 132/11kV transformation).

1. With the secondary windings parallel connected as shown in figure 6.13 the demands on each pair of windings must be reasonably well balanced to obtain satisfactory voltage control, this can be achieved relatively easily when a double busbar 11kV switchboard with on load remote controlled busbar isolators is used, however, double busbar switchboard costs are 50% to 100% higher than a single busbar version.

2. the full transformer rating cannot be achieved unless the demand on its secondary windings are balanced,

3. voltage control problems can be overcome by parallel connection of the secondary windings as shown in figure 6.14. However during 132kv fault outages the associated 11kv network is disconnected from supply and relies on an automation scheme to restore supplies for permanent faults. This operating arrangement is effectively a single circuit supply and is unlikely to comply with the requirement of section 2.3 (single circuit supplies) of this manual,

4. Unless the load density is high and thus feeder circuit distances to adjacent 11kV infeed points are short there may be insufficient transfer capability.





There use should be limited to high load density areas, eg city centres or high demand customers, where load transfers are available to adjacent substations (see section 2.4).

Parallel Connection Arrangements for 132/11/11 transformers Figure 6.13 Figure 6.14

Circuit 2Circuit 1

GT1 GT2

11kV 11kV

6.5.4 Switchgear Fault Ratings

When assessing the fault capability of circuit breakers the maximum peak make and maximum break conditions must be considered for 3 phase faults. Where the X/R ratio exceeds 18.85 the switchgear fault rating will be reduced to the next lower standard fault rating (eg, a 31.5kA switchboard at X/R ratio of 18.85 is de-rated to 25kA where the X/R ratio exceeds 18.85). Single phase fault levels for 66kV, 33kV and 11kV switchboards are normally within the capability of the circuit breakers due to neutral – earth impedance. Note: and X/R ratio of 18.85 is equivalent to a DC time constant of 60mS.

primary network design manual

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