MODELLINGRENEWABLEENERGYRESOURCEAND THE ELECTRICITY NETWORK (EAST MIDLANDS REGION)

ReportNumber:K^L/00297/REP

DTI/Pub URN 02/1562

Contractor Power Technology, Powergen

Prepared by P A Newton and T Ma

The work described in this report was carried out under contract as part of the DTI Renewable Energy Programme. The views andjudgements expressed in this report are those of the contractor and do not necessarily reflect those of the DTI.

First Published 2002 © Crown Copyright EXECUTIVE SUMMARY

Introduction

This study examines the capability of the electricity distribution network in the East Midlands to accept embedded generation, against the background of a UK policy to encourage growth in CHP and renewable generation schemes. Embedded generation is generation that is directly connected to distribution networks rather than to the transmission system.

The UK policy aims to improve the diversity, security and sustainability of energy supplies and to contain the effects of energy supply on the global environment. Hence, the Government has set the following targets relating to energy supply and use:

• Reduce the UK’s CO2 emissions by 20% below 1990 levels by 2010;

• Increase energy efficiency in domestic housing by 30% over a ten year period;

• Increase installed capacity of Combined Heat and Power (CHP) from 4GW to 10GW by 2010;

• Meet 5% of electricity requirements from renewable energy sources by 2003, rising to 10% by 2010.

The targets for CHP and renewable generation schemes will result in a significant growth in embedded generation. This is predicted to comprise a large number of generation projects ranging in size from small photovoltaic and domestic CHP schemes of a few kilowatts and less, up to large industrial CHP schemes and wind farms of over 100MW. Some of this generation will have a predictable and controllable output but a considerable proportion will be highly intermittent.

Consequently, embedded generation is expected to make a large impact on the future design and operation of distribution networks. This view is supported by studies undertaken of real embedded generation projects in recent years which have highlighted various constraints and reinforcement requirements.

A number of regional studies have previously been performed to examine the factors and available resources which will encourage or impede the implementation of these targets. The output of these studies has been a set of targets for energy efficiency, CHP and renewables for each region.

Objectives

This study was commissioned to build on the resource study completed for the Government Office East Midlands by examining the set regional targets in relation to the capacity of the distribution network. The objectives of the study are to:

1 (i) Review two sample distribution networks (one urban and one rural) in the East Midlands and identify opportunities for connection of generation and network constraints.

(ii) Review the East Midlands resource study and assess the set regional targets against the capacity of the distribution network.

(iii) Identify and prioritise steps that could be taken to reduce network constraints and increase the capability of the network to accept embedded generation.

(iv) Provide a description of the regional network and diagrams that will indicate to developers the capability of the existing network to accept embedded generation.

(v) Document the issues in developing a consistent format for similar studies across the UK distribution networks.

Work Performed

Detailed network studies were performed for two sample networks: Leicester bulk supply network was selected to represent an urban network and Boston bulk supply network to represent a rural network. The 132kV networks of the grid groups covering these areas (Enderby and Walpole respectively) were also studied. Therefore, connection points from major 132kV busbars at grid supply points down to 11kV primary substations were examined. The network downstream of 11kV primary substations was not assessed although detailed studies were performed for sample connection points on 11kV feeders.

A range of power system studies were performed based on present planning standards and practices, to identify the constraints and capabilities of the existing network, including;

• load flow to examine voltage profile and overloading

• fault level analysis

• transient studies to examine generator and network stability following faults on the network and voltage step change due to generator tripping

The range of CHP and renewable technologies which are expected to develop will largely utilise synchronous generators, asynchronous generators and converter connected generators and these were all included in the studies.

The study results, showing the maximum connection capacity at each connection point are presented in tabular form and also on network diagrams.

The second stage of the study reviews the embedded generation already in operation in the East Midlands and the proposed targets for growth in CHP and renewables by 2010. The overall, simultaneous capacities of the Leicester and Boston study areas are then assessed and these results are then extrapolated to cover the whole East Midlands region (comprising Derbyshire,

2 Leicestershire and Rutland, Lincolnshire, Northamptonshire and Nottinghamshire). This extrapolation draws on the results of a detailed fault level assessment of the whole East Midlands network, and also on known specific power flow constraints caused by line thermal ratings or transformer tap changer reverse power flow constraints.

The distribution of spare network capacity for the region is identified from this analysis by grid group and by county, and is then used in two assessments of the regional targets. The first assessment assumes the development of renewables only; the second assumes the development of both CHP and renewables.

The third stage of the study reviews the main constraining factors and potential solutions. These are summarised and are then discussed in detail. Four improvement scenarios are then studied, based on improvements to remove transient stability (two stages), fault level and power flow constraints. The additional spare network capacity obtained from these improvements is identified and used in further assessments against the 2010 regional targets for CHP and renewables. The actions to improve network capacity are then recommended and prioritised.

The final stage of work identifies the issues that need to be considered in creating a common format for similar studies of other UK distribution networks.

Results

The power system studies of the Leicester and Boston networks have identified several major constraints. The tables below indicate the range of connection capacities (in MW) for the connection points studied, as limited by the various technical constraints (these are non-simultaneous capacities, ie assuming connection of only one generator at a time). Severe constraints are highlighted in bold. The results for connections to 11kV feeders are based on only a small sample of connection points and therefore should not be treated as firm limits for the whole network. Load flow constraints include voltage rise and thermal overloading constraints.

LEICESTER Generator Connection Capacities (MW) (synchronous 132kV 33kV 11kV 11kV generators) primaries feeders Load flow 126-450 23-114 25-32 6-7 Fault level 0 0 0-5 3 Transient stability 150-230 1 0 0

3 BOSTON Generator Connection Capacities (MW) (synchronous 132kV 33kV llkV llkV generators) primaries feeders Load flow 74-110 5-85 1.5-24 0.3-1.9 Fault level 95-200 6-60 0-20 17-19 Transient stability 75-150 0-30 0 0

BOSTON Generator Connection Capacities (MW) (asynchronous 132kV 33kV llkV llkV generators) primaries feeders Load flow 106-110 13-99 1.5-22 0.4-7 Fault level 170-200 4-60 0-40 >20 Transient stability 40-100 8-16 0 0

The capacity of the network across the East Midlands region to accommodate the renewables and CHP targets given in the regional resource study is illustrated in the following two figures.

500

450 □ Existing Generation □ 2003 Target 400 □ 2010 Target 350 ■ Network Capacity 300 & 250 o o 200 § 150 O 100 50 I h i-r 1 ■ ^ 1 Leics Lines Northants Notts East Midlands

Capacity of the East Midlands Network to Accommodate Renewables only (assuming no new CHP)

4 1300 1200 □ Existing Generation 1100 □ 2010 Target - 1000 ■ Network Capacity Z 900 % 800 700 U 600 8 500 | 400 o 300 200 ■ fl 100 ■ ■ n ri^ 0 ■ _ t=LLzj=t Derby s Leics Lilies Northants Notts East Midlands

Capacity of the East Midlands Network to Accommodate Renewables and CHP

The capacity of the network can be increased by making several improvements to remove transient stability, fault level and power flow constraints. The following figure indicates the improved capacity resulting from four improvement scenarios.

4000 ■ 2010 Target 3500 ■ Existing Capacity ^ 3000 n Plus TS Upgrades (1st staae) S ■ Plus FL Upgrades % 2500 □ Plus TS Upgrades (2nd stage) O A 2000 ■ Plus Power Flow Upgrades 0 2 1500 1 1 1000 ]] 500 jJlmjT 0 _ M 11, nAl, nrO , gJ-CD , rJ~l_l^ Derby s Leics Lines Northants Notts East Midlands

Capacity of the East Midlands Network to Accommodate Renewables and CHP with Four Improvement Scenarios

5 Conclusions

The targets for 2010 set by the East Midlands regional resource study for installed generating capacity from CHP and renewables total 1174.1MW, as shown in the following table.

CHP Renewables Total 2010 Target (MW) 708.6 465.5 1174.1 Existing (MW) 368.6 44.7 413.3 Total Network 822 Capacity (MW)

The total capacity of the existing distribution network serving the East Midlands, for CHP and renewables, has been assessed in this study to be 822MW, including 413.3MW of existing CHP and renewable generation. There is therefore capacity for further growth of 409MW; however, the total network capacity falls short of the 2010 target by 30%.

If renewables only is considered (ie assuming zero growth in CHP), the total potential network capacity for renewables is 454MW, including nearly 45MW of existing renewables. This fallsjust short of the 2010 target of 465.5MW.

However, the existing network is not adapted (and was never intended) to easily accommodate significant quantities of embedded generation and many constraints exist across the whole network. Consequently, the flexibility of the network is very low and the spare capacity, which is comprised mainly of connections to the 132kV and 33kV networks, is unevenly distributed and highly lumped. It would only be fully realised by developing the optimum size of generation at all favourable sites. Generation connecting at other sites will encounter constraints. For example,

• 52% of the 63 bulk supply groups which serve the region at 33kV and below cannot accept any additional embedded generation at all.

• Only 10% ofbulk supply groups have a spare capacity above 10MW.

The majority of constraints arise due to fault levels, transient stability and voltage rise. These have been illustrated in the detailed studies of Leicester and Boston. In Leicester, high fault levels at Leicester 132kV substation and at two 11kV primary substations restrict connections to the whole 132kV and 33kV networks in that area and also to the two 11kV networks concerned. Fault level constraints are less prominent in the Boston network.

Transient stability criteria impose very severe restrictions, precluding most generator connections to any 11kV network (and below) if current planning standards are applied. The 33kV network in Leicester was also found to be severely constrained. These constraints arise primarily due to slow network fault clearance times, especially on 11kV networks. In addition, inertias of

6 many modern small embedded generating units are very low and this contributes to poor transient performance even when fault clearance times are fast (eg on 132kV and some 33kV networks).

Generators which are remote from major substations and are connected into existing network lines or cables are also likely to be constrained by voltage rise in the connecting circuit. This will apply to many of the smaller embedded generating schemes. The connecting circuits also occasionally impose constraints to prevent thermal overloading.

Four stages of improvements have been identified which will improve the total capacity of the network to accept embedded generation and reduce the number of substations subject to constraints:

Total network BSP capacity for CHP groups and renewables with no (MW) spare capacity Add. Cum. 0. Existing network (base case) 822 52% 1. Relax transient stability requirements 655 1477 24% and arrange for some generators to trip following network faults 2. Replace or upgrade highly stressed 721 2198 10% substation plant to provide higher fault level capacity 3. Improve generator and network 1250 3448 10% transient performance eg by faster fault clearance times and improved generator characteristics 4. Circuit uprating to remove local 106 3554 0% power flow constraints

Although it appears that the first stage of improvements will provide sufficient additional network capacity to enable the 2010 targets to be met, the network remains highly constrained with 24% of bulk supply groups having no spare capacity at all. It is therefore considered that the first two stages of improvements will be required to provide sufficient flexibility to allow the 2010 targets for CHP and renewables to be met. Improved transient performance may also be required in some cases, or if higher targets are set beyond 2010.

It should be noted that additional reinforcements in the distribution system, such as higher capacity and/or additional circuits, will certainly be required if large proportions of the above capacities are required for generation dispersed on the 33kV, 11kV and low voltage networks, away from major substations.

7 The enhanced network capacity of 3.5GW is limited by the strength of the connections (ie supergrid transformers) to the transmission system. Utilisation of half of this capacity should enable renewables to supply 20 to 30% of the region’s electricity energy demand, depending on the mix of technologies.

Increasing the capacity of the distribution network above 3.5GW would require either more or stronger connections to the transmission system, or improved balancing between load and generator output. For example, higher rated generating plant could be installed and operated at full output during high load but constrained down at times of low load. This additional generation connected during high load conditions would further stress the performance of the network with respect to fault levels and transient stability and would therefore be likely to require additional reinforcements to the network.

Recommendations

The following actions are recommended to improve the capability of the network to accommodate embedded generation. These are based on technical considerations and may be subject to constraints arising from the current commercial and regulatory environment.

(i) Apply relaxed transient stability requirements, allowing some generators to trip (before pole-slipping or other instability occurs) if they cannot remain connected for certain network faults. Suitable protection should be specified to ensure fast and positive tripping eg intertripping.

(ii) Specify pole-slip protection to provide positive back up protection on all synchronous generators.

(iii) Specify power system stabilisers on low inertia generators.

(iv) Initiate a programme of uprating of substation plant to increase fault rating, eg to 25kA at all high voltage levels from 6.6kV to 132kV. This will make connection capacity available at a large number of sites, thus improving flexibility in generator location, without compromising transient stability or quality of supply. The substations which should be targeted first are those where existing fault levels are close to ratings.

(v) Develop generator voltage control schemes to control generator reactive power output and also active power output as necessary, to ensure network voltages remain satisfactory. This will mainly apply to generation which is connected remotely from source substations which already provide automatic voltage control.

(vi) Uprate two 132kV double circuits between Corby, Irthlingborough and Kettering to allow additional unconstrained generation in the Corby area.

8 (vii) Replace two 132/33kV 45MVA bulk supply transformers at Annesley with modern units to provide a reverse power capability. This will enable additional unconstrained generation in the north Nottingham area.

(viii) As growth in embedded generation continues, it will be necessary to improve network fault clearance times to prevent degradation of power quality and security of supply caused by large quantities of rotating machines, many having low inertias.

The following areas are recommended for further research, development and implementation:

(ix) Fault current limiters (eg using superconductors).

(x) Generator series braking resistors (to improve generator transient performance).

(xi) Specification of a minimum value of generator inertia constant (to improve generator transient performance).

The following factors need to be considered to ensure consistency of similar studies of other UK distribution networks:

(i) Study methodology appropriate to large electrical networks.

(ii) Measurement of total network capacity including flexibility.

(iii) Requirements for computer models of distribution networks including embedded generation.

(iv) Assumptions made about generator data, network conditions and planning criteria.

This study has been performed by Power Technology, Powergen. The views and judgements expressed are not necessarily those of East Midlands Electricity.

9 CONTENTS

1 INTRODUCTION ...... 11

2 STUDY OBJECTIVES ...... 13

3 GENERATION CONNECTION CAPACITIES ...... 14

3.1 Description ofNetwork Study Areas ...... 14 3.2 Generator Technologies and Models...... 15 3.3 Generator Connection Study Methodology...... 19 3.4 Non-Simultaneous Generator Connection Capacities...... 23 3.5 Generator Connection Capacities of 11kV Feeders ...... 32

4 REGIONAL TARGETS AND NETWORK CAPACITY...... 34

4.1 Targets for Electricity Generation from CHP and Renewables in the East Midlands ...... 34 4.2 Network Capacity of the Study Areas ...... 37 4.3 Network Capacity in the East Midlands Region ...... 39 4.4 Commentary: County Network Capacities and Targets ...... 47

5 ENHANCEMENT OF NETWORK CAPACITY ...... 50

5.1 Summary of Generation Constraints and Potential Solutions...... 50 5.2 Discussion of Generation Constraints and Potential Solutions ...... 52 5.3 Network Improvement Scenarios ...... 66 5.4 Recommended Actions to Improve Network Capacity ...... 72

6 CREATING A COMMON STUDY FORMAT ...... 74

6.1 Study Methodology for Large Networks ...... 74 6.2 Measures of Regional Network Capacity...... 75 6.3 Computer Model Requirements ...... 75 6.4 Assumptions in Study Methodology ...... 76

7 REFERENCES ...... 78

8 GLOSSARY...... 79

APPENDIX A DIAGRAMS OF NETWORK CAPACITY

10 1 INTRODUCTION

The supply and use of energy has come under increasing scrutiny in recent years and is generally considered to pose an increasing threat to the world’s environment, principally through pollution and the effects on climate. At the same time, it is predicted that in the near future, there may be a degradation in the diversity, security and sustainability of energy supplies if development continues to progress purely under the influence of market forces.

In order to contain these effects, the UK Government has set several targets relating to energy supply and use, including:

• Reduce the UK’s CO emissions by 20% below 1990 levels by 2010;

• Increase energy efficiency in domestic housing by 30% over a ten year period:

• Increase installed capacity of Combined Heat and Power (CHP) from 4GW to 10GW by 2010;

• Meet 5% of electricity requirements from renewable energy sources by 2003, rising to 10% by 2010.

To address these targets, a number of regional studies have been completed. These studies have considered various factors which will encourage or impede the development of CHP and renewable electricity generation schemes, for example available energy resource, scheme economics, maturity of technology, planning and consents, environmental impacts etc. The outcome of the studies has included a set of recommended targets, on a regional basis, for CHP and each different renewable technology.

The purpose of the present study is to now examine, in detail, the capability of a sample East Midlands Electricity (EME) distribution network, to accept electricity generation from CHP and renewable sources, with particular reference to the targets set in the regional resource study.

Generation and distribution of electricity from CHP and renewable sources presents a number of technical differences and challenges compared with conventional power stations. The latter usually comprise few generating units of very large capacity and are connected to the high voltage transmission network (typically at 400kV or 275kV, occasionally at 132kV). This transmission network is generally very robust and has been designed and developed over many years specifically for the purpose of interconnecting large power stations and transmitting power from large centres of generation (located near to fuel sources) to large load centres (synonymous with large population centres).

11 Conversely, electricity generation from CHP and renewable sources typically involves many individual generating units of small size. These small generating units are most cost-effectively connected at much lower voltages, for example 33kV, 11kV or even lower voltages. They therefore largely seek to be connected to the distribution system, of which the primary function is to distribute electrical energy from the higher voltage, higher capacity transmission system to the many large and small, industrial, commercial and domestic consumers of electricity. Generation connected to the distribution system is known as embedded generation.

The distribution system has not, historically, been designed to accommodate large quantities of embedded generation and because of this there are many constraints which may be met in practice due to limitations in the capabilities and performance of the network.

This study has been performed by Power Technology, Powergen. The views and judgements expressed are not necessarily those of East Midlands Electricity.

12 2 STUDY OBJECTIVES

2.1 Review two typical distribution networks (one urban and one rural) and identify locations where generation can be accepted and where there are constraints. Quantify the constraints and the magnitude and other properties of the generation that could be accepted at the various locations

2.2 Review the East Midlands renewable energy resource study and assess the targets for each technology with reference to the capability and constraints of the distribution network, taking into account, where known, the likely location of renewable developments.

2.3 Identify and prioritise the most cost-effective steps that could be taken to increase the capability of the network to accept embedded generation, taking into account, where known, the likely location of renewable developments.

2.4 Provide a description of the regional network and diagrams that will indicate to developers the capability of the existing network to accept embedded generation.

2.5 Document the issues in developing a consistent format for similar studies across the UK distribution networks.

13 3 GENERATION CONNECTION CAPACITIES

3.1 Description ofNefrvork StudyAreas

The opportunities for connection of embedded generation have been examined in detail in the following two areas of the East Midlands network:

• Leicester Bulk Supply Point network: this area represents a typical urban network;

• Boston Bulk Supply Point network: this area represents a typical rural network. This network was selected as it is one of the few East Midland’s networks which are close to the coast and therefore available to the complete range of renewable technologies, including offshore wind.

Each of these bulk supply networks comprises the 132/33kV bulk supply point substation, 33kV feeder circuits, 33/11kV primary substations and 11kV feeder circuits. In addition, the study areas were extended to include the complete 132kV network for the two grid supply groups, Enderby and Walpole, which respectively supply Leicester and Boston bulk supply points.

Generation connections were examined at the following connection points in the two study areas:

• 132kV busbars at Enderby and Walpole grid supply point substations;

• 132kV connections at all bulk supply points within Enderby and Walpole grid groups;

• 33kV busbars at Leicester and Boston bulk supply point substations;

• 33kV connections at all primary substations within Leicester and Boston bulk supply networks;

• 11kV busbars at all primary substations within Leicester and Boston bulk supply networks.

Studies were also performed to identify the capacities which could typically be expected for generation which is to be connected to existing 11kV feeder circuits at some distance from the primary substation. These capacities are often limited by the requirement to maintain an acceptable quality of supply to other customers connected to the circuit. In such cases, the alternative is to connect the generator directly to the primary substation via a dedicated generator circuit.

14 The number and capacity of infeeding transformers at the grid supply, bulk supply and primary substations in the two study areas are detailed below

Leicester Area Substation Capacities

Enderby Grid Supply Point (400/132kV) 3 x 240MVA Leicester Bulk Supply Point (132/33kV) 2 x 120MVA Leicester Primary (33/11kV) 2 x32MVA Highfields Primary (33/11kV) 2 x 19MVA Redcross Street Primary (33/11kV) 2 x32MVA Jupiter Primary (33/11kV) 2 x 2'MVA Braunstone Primary (33/11kV) 2 x 19MVA

Boston Area Substation Capacities

Walpole Grid Supply Point (400/132kV) 4 x 240MVA Boston Bulk Supply Point (132/33kV) 2 x 90MVA Mount Bridge Primary (33/11kV) 2x15MVA Wrangle Primary (33/11kV) 2 x9.5MVA Sleaford Road Primary (33/11kV) 2 x 19MVA Donington Primary (33/11kV) 2 x9.5MVA Langrick Primary (33/11kV) 1 x 6MVA Tattershall Primary (33/11kV) 2 x 19MVA Kirton Primary (33/11kV) 1 x9.5MVA Stickney Primary (33/11kV) 1 x9.5MVA

3.2 Generator Technologies and Models

The renewable technologies which are being planned for current and future developments will normally utilise one of the following forms of electrical generator: directly connected synchronous generator; directly connected asynchronous (induction) generator; converter connected generator.

Directly Connected Synchronous Generators

This is the conventional generator and will be used in conjunction with steam and gas turbines or engines (eg as used in biomass, energy from waste and landfill gas schemes).

Three types of synchronous generator model were used in the studies to represent typical small, medium and large generating units. The parameters used in each model are shown in Table 1. The assumed inertia constants of 2MWs/MVA for machines less than 50MW and 3MWs/MVA for larger machines, represent average figures erring on the pessimistic side. The range of inertia constants for generating units, including the prime mover, varies widely and it is not possible to predict this value with accuracy for future plant. Conventionally, many large generating units have high inertias, with resulting inertia constants (H) of 6MWs/MVA for example. However, many embedded

15 generators are now being proposed and installed with low inertia constants, in the range 1 to 2MWs/MVA and occasionally even less. The dynamic performance of these machines must therefore be carefully considered such that the stability of the wider network is not impaired as a result of severe network disturbances.

Generator connections to the 33kV and 132kV networks are made via generator transformers and the parameters used in the studies for these are also given in Table 1. Connections to the 11kV network are assumed to be direct ie a directly connected 11kV generator without generator transformer. In practice, smaller generators (eg 1MW and below) may be connected via 11/0.4kV generator transformers.

Directly Connected Asynchronous (Induction) Generators

These provide superior damping to synchronous machines and are therefore widely used by wind turbine manufacturers. They may also be used in small hydro schemes. Asynchronous generators have been studied in the Boston network but not in the urban Leicester area where they are not expected to be used.

In these studies, asynchronous generators have been modelled based on conventional wind turbine generators as installed in the 1990s and still being installed today. These machines comprise a conventional induction generator with a cage type rotor winding and a direct connection of the stator winding (typically 690V), via a step-up transformer, to the network. Such a machine operates practically as a fixed speed machine since the speed changes insignificantly from no load to full load. The generator demands (ie consumes) reactive power and this demand increases with generator output. In the studies, a power factor correction capacitor has been connected to the generator terminals to compensate for the no-load reactive requirement of the generator. This is the minimum level of compensation typically installed. Thus, when generating, the generator does place a moderate reactive power demand on the network. This model provides worst case behaviour of a wind turbine asynchronous generator and therefore the results obtained are on the conservative side.

An inertia constant of 4MWs/MVA has been used for asynchronous machines in the transient stability studies. This is a typical value for a medium to large wind turbine.

The wind industry has introduced several developments in asynchronous generation schemes in recent years, the most significant being the double-fed induction generator. These include a wound rotor winding instead of the cage winding and this has terminals brought out of the machine via sliprings and brushes. The rotor winding then receives an excitation supply from a rotor AC/DC/AC converter which is supplied from the stator terminals of the generator. The rotor converter control system performs two functions. Firstly, it allows control of the generator speed which gives advantages of reduced

16 mechanical loadings and improved energy yield by running at optimum rotor wind speed for the actual wind conditions. Secondly, it allows control of the generator power factor. This allows the reactive power demand placed on the network to be reduced if required. Some machines have the capability to generate or consume reactive power within a limited range. This provides the possibility of providing network voltage support services, which are normally available as standard from a synchronous machine.

Double-fed induction generators are a relatively recent introduction in the wind industry and manufacturers are not yet releasing full details of the operating characteristics of their machines. Compared to conventional fixed speed asynchronous generators, the power factor control capability of double-fed induction generators will provide greater flexibility and improve their impact on network voltages and loadings. They are also expected to provide a superior transient response to network voltage dips. However, the stator windings of these machines are still directly connected and early indications are that these machines will still provide significant contributions to network fault levels, possibly increased due to the modified rotor voltages

Converter Connected Generators

Photovoltaic cells are connected to the network via inverters. Variable speed converter systems may also be considered in some wind turbine applications although fully rated converters are not common due to cost and losses.

There are two main advantages of converter connections for generators. Firstly, many converters limit short-circuit current flows resulting in a significantly reduced impact on fault levels. Secondly, when used to connect rotating (synchronous or asynchronous) generators, the converter allows the generator to operate at a frequency independent of the network frequency. This improves the capability of the generator to withstand short transient disturbances without adverse effects on the network. For example, the potential problem of a generator losing synchronism with the network (ie pole-slipping) is eliminated

A potential disadvantage of converters is that they may generate harmonic currents which will increase harmonic distortion in the network voltage. However, experience has shown that suitable harmonic filters may be included in the converter design to control harmonics within acceptable levels.

17 Small Medium Large

Power output P MW P<20 20 50

Rated lagging 0.80 0.85 0.85 power factor (at full output)

Rated leading 0.95 0.95 0.95 power factor (at full output)

Synchronous p.u. 2 2 2 reactance Xd

Transient reactance p.u. 0.25 0.25 0.25 X'd

Sub-transient p.u. 0.15 0.15 0.15 reactance X”d

Transient o/c time s 4 6 8 constant T’do

Sub-transient o/c s 0.05 0.05 0.05 time constant T”do

Armature time s 0.12 0.25 0.3 constant Ta

Inertia constant H MWs/ 2 2 3 MVA

Generator transformer

Resistance R p.u. 0.007 0.005 0.005

Reactance X p.u. 0.15 0.15 0.15

Table 1 Synchronous Generator Models

All per unit quantities are based on the generator MVA rating.

18 3.3 Generator Connection Study Methodology

Load Flow Studies

Load flow studies have been performed to confirm the acceptability of generator connections under steady state conditions. The criteria used to limit the amount of generation which can be connected at each connection point are as follows:

• All circuit loadings should remain within ratings (thermal ratings)

• Network voltages should remain within limits

• Reverse power flow in transformer tap changers is not allowed unless the tap changer has reverse power capability or can be readily upgraded

The above criterion must be satisfied with the outage of any one circuit in the distribution network and under worst case (usually minimum) loading conditions.

The network voltage limits used in the studies are as follows:

132kV network: ±6% of nominal

33kV network: ±6% of nominal

11kV network: ±3% of nominal

The 132kV network is actually permittedto operate to ±10% of nominal although this wide range would not normally be encountered operationally under most conditions. Similarly, 11kV and low voltage supplies to customers must remain within ±6% and +10/-6% of nominal respectively. It is necessary to ensure that all connection points on remote sections of the network comply with this requirement. Also, voltage control on the low voltage system is limited due to the use of transformers with off-circuit tap changers; the transformer therefore operates with a fixed voltage ratio. Consequently, the 11kV voltage must be tightly controlled in practice over much of the network and hence ±3% has been used as an operational range.

The effect of generation on the voltage profile of the network is heavily dependent on the operating power factor of the generator. All generators (excluding asynchronous generators) of 50MW and above must comply with the requirements specified in the Grid Code ie be capable of generating their rated power over the whole power factor range from 0.85 lagging to 0.95 leading, measured at the generating unit terminals. The requirements for smaller generators are normally agreed with the Distribution Network Operator (DNO) on an individual basis, and such machines are frequently required to export at

19 a power factor of unity, measured at the connection point. As the level of embedded generation increases, it is likely that DNOs will require generators to provide a degree of control of reactive power export, to assist with local voltage control and such that generator export power factor is reasonably matched to the power factor of the local load. This will ensure that the power factors on network transformers, and particularly tap changers, remain acceptable. Thus, for the purpose of these studies, a capability to export rated power over the whole power factor range from 0.95 lagging to unity, measured at the connection point, has been assumed for all generators less than 50MW. The connections for all generators (except asynchronous generators) have therefore been assessed with full consideration given to these requirements on generator operating power factor range.

Fault Level Studies

Studies were performed to determine the maximum capacities for additional generation as limited by the fault ratings of existing network circuit breakers. Three phase making and breaking fault levels were checked at all 132kV, 33kV and 11kV busbars in the study areas. Single phase fault levels were also checked on the 132kV network (as this is solidly earthed and can therefore experience high earth fault levels)

Transient Stability Studies

Transient stability studies were performed to investigate the effects of short-circuit fault disturbances on the network and to establish the maximum generation which can be connected without giving rise to network or generator instability following such an event. Instability can be defined as any of the following events:

• Pole-slipping of one or more synchronous generators

• Overspeeding of one or more asynchronous generators

• Voltage collapse of a distribution network resulting in operation of undervoltage protection and interruption of supplies

The problem of stability of a.c. electric power systems has long been recognised and transmission systems have traditionally been planned such that they can withstand a range of short-circuit fault events, such as a fault on any one circuit or transformer, and remain stable. These principles have been extended to cover generation connected to distribution systems (eg see Engineering Recommendation G75). There are many factors which influence stability following short- circuit faults, but the most important are:

• the severity of the short-circuit

20 • the loading of rotating machines (relative to the strength of the network)

• the inertia constant (H) of rotating machines

Short-circuit severity is determined by a number of sub-factors. At the planning stage, it is normal practice to make a number of worst case assumptions such as:

• the short-circuit is between all three phases

• the short-circuit has negligible impedance ie it is a solid ‘bolted’ fault

• the short circuit could occur at any location, the worst case for any particular generator being near to the generator terminals

The one remaining factor which affects fault severity is the fault duration which is determined by the operating time of the protection relays and circuit breakers which must operate to clear the fault. In distribution systems, fault clearance times on the 132kV network are comparable with those on the transmission system and are typically in the range 100 to 200ms (assuming operation of main protection rather than back-up protection). Similar clearance times may also apply to certain sections of the 33kV network. However, many 11kV networks, and also some sections of 33kV network, have time-graded main protection schemes which can result in normal clearance times of 0.5s to 1s. The upper end of this range is an order of magnitude slower than would be expected on the transmission system.

An additional problem facing distribution systems is that many modern small generating unit prime movers have very low inertias. The inertia constant for a typical large generator connected to the transmission system might be 6MWs/MVA (on generator rating), whereas small generators with inertia constants of less than 2 and even less than 1MWs/MVA are frequently being encountered. The inertia constants used in these studies (see section 3.2 and Table 1 above) should be carefully noted as they directly determine the transient performance of the generation schemes.

As a first approximation, it may be assumed that stability is directly proportional to generator inertia and inversely proportional to fault clearance time. Thus, design for the maintenance of stability of low inertia generators in distribution systems, under worst case fault scenarios, is often an extremely difficult proposition. The key requirement to ensure stability is almost always fast fault clearance, by means of high speed protection schemes and circuit breakers. Whilst the transmission system has these attributes, many distribution networks do not.

21 In these studies, the following fault clearance times have been assumed, for all circuit breakers in the study areas:

132kV network: 150ms

33kV network: 200ms

11kV network: 500ms

The clearance time of 500ms is slow enough to prohibit the connection of any embedded generation, unless the requirement for the generator to remain stable is relaxed. This will be discussed further in a later chapter

In addition to observing angular stability of rotating plant, voltage recovery to -10% of nominal within 0.5s at the connection point has also been applied as a criterion for acceptable transient performance. This is a normal undervoltage protection setting for embedded generation and must not be exceeded otherwise the generation will not successfully remain connected following the clearance of the fault.

Voltage Step Change Studies

DNOs normally impose a limit on the maximum change of network voltage which may occur due to changes in the output of generation. Engineering Recommendation G75/1 sets a maximum step change of 6% for unplanned trips and this has been used in these studies. This relates to a trip of the generator from full load (normally, generator output would be reduced in a controlled manner before opening the generator circuit breaker).

This limit does not necessarily limit the total generation which can be connected at any one connection point, but it does limit the amount of generation which can be connected via any one circuit breaker or circuit. For example, a connection point with a voltage step change limit of 10MW might actually accommodate 20MW providing this is connected as independent units of maximum 10MW each, such that any single circuit breaker trip results in the loss of no more than 10MW

The voltage step change which does occur is heavily dependent on the operating power factor of the generator with maximum lagging power factor normally giving worst case results.

22 3.4 Non-Simultaneous Generator Connection Capacities

The network studies described above have been performed to identify the non-simultaneous generator connection capacities in the study areas. The non-simultaneous generation capacity at any given connection point is the maximum generation which can be connected there, assuming no new generation at all other connection points in the area. If several generators are to be connected, then the connection point capacities may need to be reduced due to interactions between sites

Separate limits have been calculated due to each of the individual study considerations (load flow, fault level, stability and voltage step change)

The results are given in Tables 2 to 9. In Tables 2, 5 and 6, the figures represent the maximum generation capacities which can be accepted as limited by each technical study in turn (ie limit due to load flow consideration only, limit due to fault level consideration only etc). Thus the overall capacity is the minimum from all the individual studies; these are summarised in Tables 3, 4, 7, 8 and 9.

Results are presented for synchronous generators and converter connected generators in the Leicester area and synchronous, asynchronous and converter connected generators in the Boston area. Asynchronous generators have not been studied in the Leicester area as the technologies employing this form of generation (mainly wind) are unlikely to be used in this urban area.

23 Substation Capacity MW Load flow Fault Transient Voltage Level Stability Step

Enderby 132kV 450 0 230 220 Leicester 132kV 448 0 220 200 Leicester East 132kV 153 0 190 190 Leicester North 132kV 150 0 210 195 Coalville 132kV 126 0 150 100 Wigston 132kV 140 0 190 160

Leicester 33kV 114 0 1 48 Highfields 33kV 23 0 1 48 Redcross Street 33kV 37 0 1 38 Jupiter 33kV 28 0 1 38 Braunstone 33kV 23 0 1 40

Leicester 11kV 32 0 0 13 Highfields 11kV 25 5 0 10 Redcross Street 11kV 31 0 0 13 Jupiter 11kV 29 3 0 11 Braunstone 11kV 26 3 0 9

Table 2 Leicester: ConnectionCapacities forDirectlyConnected Synchronous Generators (non-simultaneous)

24 Substation Capacity MW Limiting Factor(s)

Enderby 132kV 0 Fault level Leicester 132kV 0 Fault level Leicester East 132kV 0 Fault level Leicester North 132kV 0 Fault level Coalville 132kV 0 Fault level Wigston 132kV 0 Fault level

Leicester 33kV 0 Fault level & TS Highfields 33kV 0 Fault level & TS Redcross Street 33kV 0 Fault level & TS Jupiter 33kV 0 Fault level & TS Braunstone 33kV 0 Fault level & TS

Leicester 11kV 0 Fault level & TS Highfields 11kV 0 Transient stability Redcross Street 11kV 0 Fault level & TS Jupiter 11kV 0 Transient stability Braunstone 11kV 0 Transient stability

Table 3 Leicester: Summary ofConnectionCapacities forDirectly Connected Synchronous Generators (non-simultaneous)

25 Substation Capacity MW Limiting Factor(s)

Enderby 132kV 450 Thermal rating & voltage drop Leicester 132kV 448 Thermal rating Leicester East 132kV 153 Thermal rating Leicester North 132kV 150 Thermal rating Coalville 132kV 12% Thermal rating Wigston 132kV 140 Thermal rating

Leicester 33kV 114 Thermal rating Highfields 33kV 23 Thermal rating Redcross Street 33kV 37 Thermal rating Jupiter 33kV 28 Thermal rating Braunstone 33kV 23 Thermal rating

Leicester 11kV 32 Voltage rise Highfields 11kV 25 Thermal rating Redcross Street 11kV 31 Voltage rise Jupiter 11kV 29 Voltage rise Braunstone 11kV 2% Thermal rating

Table 4 Leicester: Summary of Connection Capacities for Converter Connected Generators (non-simultaneous)

2% Substation Capacity MW Load flow Fault Transient Voltage Level Stability Step

Walpole 132kV 110 >200* 120 155 Boston 132kV 110 120 110 60 Skegness 132kV 74 150 75 44 South Holland 132kV '3 95 75 52 Spalding 132kV 95 150 150 120 Bourne 132kV 110 130 140 100 Stamford 132kV 100 130 100 55

Boston 33kV 85 6 0 30 Mount Bridge 33kV 18 6 2 30 Wrangle 33kV 7 >60* 30 12 Sleaford Road 33kV 23 6 3 26 Donington 33kV 5 >60* 14 9 Langrick 33kV 14 >60* 20 13 Tattershall 33kV 7 >60* 12 8 Kirton 33kV 10 >60* 20 13 Stickney 33kV 8 >60* 15 10

Mount Bridge 11kV 17 0 0 14 Wrangle 11kV 8 15 0 5 Sleaford Road 11kV 24 6 0 8 Donington 11kV 8 16 0 4 Langrick 11kV 7 20 0 4 Tattershall 11kV 8 18 0 4 Kirton 11kV 8 18 0 5 Stickney 11kV 1.5 20 0 4

Table 5 Boston: Connection Capacities for Directly Connected Synchronous Generators (non-simultaneous)

* Voltage instability occurs before fault level limit Is reached

27 Substation Capacity MW Load flow Fault Transient Voltage Level Stability Step

Walpole 132kV 110 >200* 100 150 Boston 132kV 110 >200* 60 180 Skegness 132kV 110 >200* 40 130 South Holland 132kV 108 200 45 143 Spalding 132kV 106 >200* 90 160 Bourne 132kV 110 170 85 185 Stamford 132kV 106 180 50 170

Boston 33kV 99 4 16 45 Mount Bridge 33kV 19 4 16 45 Wrangle 33kV 13 >60* 13 47 Sleaford Road 33kV 23 4 16 47 Donington 33kV 14 >60* 9 45 Langrick 33kV 14 >60* 12 50 Tattershall 33kV 15 >60* 8 47 Kirton 33kV 18 >60* 12 60 Stickney 33kV 13 >60* 9 45

Mount Bridge 11kV 15 0 0 13 Wrangle 11kV 11 38 0 13 Sleaford Road 11kV 22 15 0 12 Donington 11kV 11 40 0 15 Langrick 11kV 6 >20* 0 7 Tattershall 11kV 14 >22* 0 11 Kirton 11kV 10 >31* 0 11 Stickney 11kV 1.5 >20* 0 8

Table 6 Boston: Connection Capacities for Directly Connected Asynchronous Generators (non-simultaneous)

* Voltage instability occurs before fault level limit is reached

28 Substation Capacity MW Limiting Factor(s)

Walpole 132kV 110 Thermal rating Boston 132kV 110 Thermal rating, voltage rise & TS Skegness 132kV 74 Voltage rise & TS South Holland 132kV 75 Transient stability Spalding 132kV 95 Thermal rating Bourne 132kV 110 Thermal rating Stamford 132kV 100 Thermal rating & TS

Boston 33kV 0 Transient stability Mount Bridge 33kV 2 Transient stability Wrangle 33kV 7 Voltage rise Sleaford Road 33kV 3 Transient stability Donington 33kV 5 Voltage rise Langrick 33kV 14 Voltage rise Tattershall 33kV 7 Voltage rise Kirton 33kV 10 Voltage rise Stickney 33kV 8 Voltage rise

Mount Bridge 11kV 0 Fault Level & TS Wrangle 11kV 0 Transient stability Sleaford Road 11kV 0 Transient stability Donington 11kV 0 Transient stability Langrick 11kV 0 Transient stability Tattershall 11kV 0 Transient stability Kirton 11kV 0 Transient stability Stickney 11kV 0 Transient stability

Table 7 Boston: Summary ofConnectionCapacities forDirectly Connected Synchronous Generators (non-simultaneous)

29 Substation Capacity MW Limiting Factor(s)

Walpole 132kV 100 Transient stability Boston 132kV 60 Transient stability Skegness 132kV 40 Transient stability South Holland 132kV 45 Transient stability Spalding 132kV 90 Transient stability Bourne 132kV 85 Transient stability Stamford 132kV 50 Transient stability

Boston 33kV 4 Fault Level Mount Bridge 33kV 4 Fault Level Wrangle 33kV 13 Transient stability & thermal rating Sleaford Road 33kV 4 Fault Level Donington 33kV 9 Transient stability Langrick 33kV 12 Transient stability Tattershall 33kV 8 Transient stability Kirton 33kV 12 Transient stability Stickney 33kV 9 Transient stability

Mount Bridge 11kV 0 Fault Level & TS Wrangle 11kV 0 Transient stability Sleaford Road 11kV 0 Transient stability Donington 11kV 0 Transient stability Langrick 11kV 0 Transient stability Tattershall 11kV 0 Transient stability Kirton 11kV 0 Transient stability Stickney 11kV 0 Transient stability

Table 8 Boston: Summary ofConnectionCapacities forDirectly Connected Asynchronous Generators (non-simultaneous)

30 Substation Capacity MW Limiting Factor(s)

Walpole 132kV 110 Thermal rating Boston 132kV 110 Voltage rise Skegness 132kV 74 Voltage rise South Holland 132kV 83 Voltage rise Spalding 132kV 95 Thermal rating Bourne 132kV 110 Thermal rating Stamford 132kV 100 Thermal rating (& voltage rise)

Boston 33kV 85 Thermal rating Mount Bridge 33kV 18 Thermal rating Wrangle 33kV 7 Voltage rise Sleaford Road 33kV 23 Thermal rating Donington 33kV 5 Voltage rise Langrick 33kV 14 Voltage rise Tattershall 33kV 7 Voltage rise Kirton 33kV 10 Voltage rise Stickney 33kV 8 Voltage rise

Mount Bridge 11kV 17 Thermal rating Wrangle 11kV 8 Voltage rise Sleaford Road 11kV 24 Voltage rise Donington 11kV 8 Voltage rise Langrick 11kV 7 Voltage rise and thermal rating Tattershall 11kV 8 Voltage rise Kirton 11kV 8 Voltage rise Stickney 11kV 1.5 Tap changer power flow

Table 9 Boston: Summary of Connection Capacities for Converter Connected Generators (non-simultaneous)

31 3.5 Generator Connection Capacities of llkV Feeders

Sample studies have been performed to provide an indication of the generator connection capacities which may be expected for typical existing llkV feeders. This connection method, where feasible depending on the size of the generator, is usually a lower cost alternative to installing a new dedicated circuit between the generator and the primary substation. In the Leicester area, three connection points at Aylestone Road, Ealing Road and Welford Road secondary substations have been examined. In the Boston area, connections to three sizes of overhead line (25mm 2 copper, 50mm 2 ACSR and l50mm 2 ACSR) have been examined. The latter are based on a connection point at a distance of 5km from Donington Primary substation.

The results are given in Table 10 below.

Area / Capacity MW Substation Load flow Fault Transient Voltage Level Stability Step Leicester: Syncironous Generators Aylestone Road 6 3 0 8 Ealing Road 7 3 0 8 Welford Road 6 3 0 6

Boston: Synchronous Generators 25mm2 OHL 0.3 17 0 1.2 50mm2 OHL 0.6 18 0 1.8 150mm2 OHL 1.9 19 0 2.6

Boston: Asynchronous Generators 25mm2 OHL 0.4 >20* 0 3 50mm2 OHL 0.9 >20* 0 6 150mm2 OHL 7 >20* 0 10

Table 10 GeneratorConnectionCapacities ofTypicalExisting llkV Feeders

* Voltage instability occurs before fault level limit is reached.

The transient stability limit of 0MW applies to all of these cases as these generators will not be able to remain stable for faults on the

32 11kV network which may not be cleared for 0.5s or more. Chapter 5 describes how this problem may be overcome.

Apart from transient stability, generation is limited by either load flow or fault level constraints. In the Leicester area, fault level constraints are dominant, due to low fault level margins on the Leicester Primary 11kV network. The load flow limits on the studied circuits are relatively high and are limited by the thermal capacities of the circuits as well as by voltage rise.

In the Boston examples, the generators are connected a long way (5km) from the primary substation and the low load flow limits for synchronous generators are due to the voltage rise they cause in the circuit. These generators are assumed to be exporting at unity power factor: the constraint would be even more severe if the generators also export reactive power.

The constraints on asynchronous generators are slightly better for the smaller conductors, as these machines are assumed to be exporting at a leading power factor i.e. importing reactive power. This helps to reduce the voltage rise caused by export of active power. This effect is very notable with the 150mm2 conductor; in this case, the combined effects of exporting at leading power factor and a very low conductor resistance mean that the voltage rise problem is much reduced, and the capacity is limited by the thermal rating of the circuit.

The capacities that are limited by voltage rise will increase if the connection can be made closer to the primary substation, until they are ultimately limited by a thermal, fault level or stability constraint.

33 4 REGIONAL TARGETS AND NETWORK CAPACITY

4.1 Targets forElectricitvGeneration fromCHP andRenewables in the East Midlands

Targets for electricity generation from CHP and renewable resources for the East Midlands region have been proposed in the report Viewpoints on Sustainable Energy in the East Midlands: A study of Current Energy Projects and Future Prospects, dated March 2001 by Land Use Consultants (LUC) and IT Power. This study covers the following East Midlands counties: Derbyshire; Leicestershire (and Rutland); Lincolnshire; Nottinghamshire; Northamptonshire. Existing schemes are reviewed and targets have been proposed for the years 2003 and 2010, as follows:

Installed Capacity (MW) CHP Renewables TOTAL Existing (2002) 368.6 44.7 413.3 2003 target (ho target) 102.7 _ 2010 target 708.6 465.5 1174.1

Table 11 Summary of Targets for CHP and Renewables in the East Midlands

The targets represent the total capacities for CHP and renewable generation schemes to be installed by 2003 and 2010 (not the additional capacities required). There has been no target set for CHP in2003.

The existing generation figures quoted above are based on the latest EME information for 2002; these agree well with the figures quoted in the LUC/IT Power report of 371MW of CHP and 44.1MW of renewables. The composition of this existing generation, by county and by technology, is shown in Table 12. In addition to CHP and renewables, there also exists some 460.4MW of other embedded generation, which includes the Corby combined cycle gas turbine (CCGT) power station (406MW) and several small gas, oil and coal schemes. Thus, the total existing embedded generation connected to the EME network in the five East Midlands counties is 873.7MW.

The existing schemes represent contributions of 52% for CHP but less than 10% for renewables towards meeting the 2010 targets. The renewables target for 2003 is less than one quarter of the 2010 target.

34 Installed Capacity ( MW) Midlands

Derbyshire Leicestershire Lincolnshire East Northamptonshire Nottinghamshire

CHP 297.6 4.6 14 12.1 40.3 368.6 Onshore Wind 0.05 0.05 Hydro 1.28 1.2 2.48 PV 0.02 0.06 0.08 Municipal and 7 7 Industrial Waste (MIW) Landfill Gas 1.73 11.02 9.7 5.01 7.66 35.12 Total Renewables 3.0 11.1 9.7 5.0 15.9 44.7 Other embedded 23.0 3.5 0.8 411.5 21.5 460.4 TOTAL 323.6 19.2 24.5 428.6 77.7 873.7

Table 12 Existing Embedded Generation in the East Midlands

The target for CHP is composed of 683MW in the industrial and commercial sector and 25.6MW in the domestic sector. The LUC/IT Power report does not provide an indicative distribution of these targets between the five East midlands counties.

Table 13 shows the breakdown of the renewables target for 2010 by county and by technology. Wind power provides by far the largest contribution with onshore and offshore wind each providing over 25% of the total. The greatest accessible onshore wind resource is considered to exist in Derbyshire, Leicestershire and Lincolnshire whilst the offshore wind resource is entirely restricted to coastal Lincolnshire. Consequently, Lincolnshire is targeted to provide 210.5MW, by far the greatest proportion of the total, at nearly 50%. This high and localised target is expected to place significant demands on the distribution network and possibly also on the local transmission system. System modifications and/or reinforcements may therefore be required to accommodate the required capacity.

35 Generation Capacity (MW) Total Technology Derbyshire Leicestershire Lincolnshire Northamptonshire Nottinghamshire MW % Wind: Offshore 125 125 26.9% Wind: Onshore 40 24 48 8 2 122 26.2% Marine: Wave/Tidal 0 Biomass: Wet 1.6 1.2 1.1 0.6 0.6 5.1 7.7% Agricultural Wastes Biomass: Poultry Litter 15 15 2.2% Biomass: Energy Crops 10 20 10 6 46 9.9% Hydropower 2.8 7.8 10.6 2.2% Solar - PV 3.7 3.5 2.4 2.4 3.9 15.9 2.4% Municipal and Industrial 14 14 4 14 9 55 77.9% Waste (MIW) Landfill Gas 8.5 18 7 14 5 52.5 77.2% Anaerobic Digestion 4.1 3.1 3 4.1 4.1 18.4 4.0% TOTAL (MW) 74.7 73.8 210.5 68.1 38.4 465.5 700% Total (% of total target) 76.0% 76.9% 412% 74.6% <9.2% 700%

Table 13 Summary ofTargets for Electricity Generation from Renewables in the East Midlands by 2010

36 Of the other technologies, biomass, municipal and industrial waste and landfill gas provide significant contributions, totalling 37% of the target. Landfill gas schemes make up the bulk of existing renewable schemes in the East Midlands and currently represent over half of the 2010 target for landfill gas. Thus the biggest growth areas, after wind, are predicted to be biomass and energy from waste. The latter schemes are predicted primarily for Northamptonshire and the cities of Derby and Leicester. The remaining technologies (hydro, photovoltaics and digestion of sewage and organic waste) have relatively small targets (totalling 45MW, or 9.6% of the regional total) and should be easily accommodated given their likely highly distributed nature.

The installed capacity of 465.5MW of renewables targeted for 2010, is predicted to supply 2212GWh per annum. This equates to a combined overall load factor of 54% which is low due to the low load factors (typically 30%) contributed by wind farms. The predicted energy supply consequently represents only 9.4% of the predicted annual energy demand in the East Midlands in 2010 (23,600GWh). Therefore, this regional target has been set slightly below, not above, the national 10% target.

4.2 Network Capacity of the Study Areas

Network studies were repeated to assess the effects of simultaneous generator connections and to identify the capacity of each study area as a whole, as opposed to the maximum capacities of individual connection points.

Enderby/Leicester Area

The maximum generation capacity of the Enderby grid group is limited as follows:

• 0MW limited by 132kV and 11kV fault ratings

• 230MW limited by transient stability

• 400MW limited by the fault rating of Enderby grid supply point 132kV substation

• 500MW limited by the continuous current ratings of the Enderby grid supply transformers (400/132kV)

As shown in the previous studies, the Leicester area is presently suffering from several fault level constraints which restrict generator connections at all voltage levels from 132kV to 11kV (except for converter connections which are able to provide negligible fault level contributions). Therefore, these fault level constraints must be addressed before generator connections can be considered in this area. Switchgear upgrading at two 132kV bulk supply points and at least two 11kV primary substations would be required.

37 (It should be noted that the voltage step change limits previously calculated will limit the size of individual generating units which may be connected. However, the above limits may be achieved by installing multiple generating units with independent connection circuits)

These studies are based on 100% synchronous generation which is the most likely technology to be employed in urban areas eg for energy from waste, landfill gas, biomass and CHP schemes.

The 230MW capacity limited by transient stability considerations consists entirely of connections to the 132kV network. This is because the fault clearance times on the existing 33kV and 11kV networks are generally too slow to permit connections which will satisfy the transient stability criteria. The simultaneous connection studies showed that in this area, the 132kV network is compact and strong such that there is total interaction between the different connection points. This means that the maximum capacities of individual connection points must be reduced by the same amount as any generation which is added to a nearby connection point. Therefore, it is not possible to install several schemes to achieve a total greater than 230MW, which is the non-simultaneous maximum capacity of Enderby 132kV substation.

Connections to the 33kV and 11kV networks might be possible if one or more of the following actions is taken to overcome the transient stability problems:

• Improve the network fault clearance times

• Specify a higher value of generator inertia, as a minimum requirement

• Relax the transient stability requirements

These will be discussed further in chapter 5.

Assuming that the transient stability problems are solved, the maximum generation that can be connected to the Leicester bulk supply point at 33kV and below is as follows:

• 100MW limited by the fault rating at Leicester bulk supply point 33kV substation•

• 155MW limited by the continuous current ratings of the Leicester bulk supply transformers (132/33kV)

Walpole/Boston Area

Total new generation in the Walpole group is limited by the existing network as follows:

3' • 110MW limited by the continuous current ratings of the Walpole grid supply transformers (400/132kV)

• 150MW limited by transient stability

• 190MW to 200MW plus, depending on the exact distribution of the generation and the substation running arrangements (ie solid or split) at Walpole, Boston, Skegness and Spalding, limited by the fault rating ofWalpole grid supply point 132kV substation

It should be noted that this is in addition to the considerable level of embedded generation which already connects to the Walpole 132kV group, including Peterborough and King’s Lynn CCGT power stations (which have registered capacities of 405MW and 380MW respectively). Thus the total capacity of the Walpole group is in the order of 900MW.

As for the Leicester area, if this level of new generation is to be achieved without violating transient stability requirements, then the bulk of it will need to be connected to the 132kV network to take advantage of the faster fault clearance times there. The Walpole 132kV network extends over a larger area than the Enderby network, with greater distances between connection points. Hence, there is less interaction between multiple generation sites and there is also the capability to connect limited quantities of generation to the 33kV network in addition to the 132kV network. However, the studies have shown that the total generation in this group still cannot exceed approximately 150MW, even when generating sites are widely distributed (eg at Bourne 132kV, Skegness 132kV, Kirton 33kV, Langrick 33kV and Wrangle 33kV).

In practice, generation in this group is likely to comprise a mix of synchronous and asynchronous generation, the latter being used in onshore and offshore wind farms, which make up a large proportion of the renewables forecast for the East Midlands. It is expected that wind farm generation installed in the next few years will use double-fed induction generators (see section 3.2). These are expected to provide superior performance in terms of operating power factor and transient performance, and this may be further augmented by the use of dynamic compensation devices such as static var compensators (SVCs).

4.3 Network Capacity in the East Midlands Region

In order to assess the capacity of the East Midlands region as a whole, the results obtained from the detailed studies of Enderby and Walpole grid supply groups have been extrapolated to cover all grid supply groups in the region.

The East Midlands region considered in this study is supplied by eleven grid supply points (GSPs) ie substations where power is taken from the National Grid 400 or 275kV transmission system. In each of

39 these grid groups, power from the GSP substation is distributed to consumers via the 132kV and lower voltage distribution networks. East Midlands Electricity do not parallel adjacent grid groups, although there are normally open 132kV standby circuits between groups which can be used for abnormal feeding arrangements.

Table 14 lists these eleven grid groups and shows the counties they each serve. The table shows, for each group, the GSP firm capacity and also the total firm capacity of all the bulk supply points (BSPs) served by each group, broken down by county. (Bulk supply points are 132/33kV or 132/11kV substations.) For example, Derbyshire is supplied mainly from Chesterfield (north Derbyshire) and Willington (south Derbyshire) plus a small supply from Drakelow (near Burton- on-Trent)

It should be noted that there is not an exact fit between the area served by East Midlands Electricity and the counties included in the resource study. East Midlands Electricity also serves parts of Warwickshire, Staffordshire and Buckinghamshire: the capacity of the network serving these areas has not been included in the analysis. Also, the northern part of Lincolnshire is served by Yorkshire Electricity and this network is excluded from the analysis.

The network capacities for embedded generation identified from the detailed studies of the Enderby/Leicester and Walpole/Boston groups can be expressed in terms of the firm load capacity of each group. This analysis gives two very different results. The Enderby group has the potential for 230MW of generation, which represents approximately 50% of the Enderby grid transformer firm capacity. This is limited by transient stability and is conditional on reinforcements to solve existing fault level constraints. Conversely, the Walpole group has the capacity to accept up to 900MW of generation, of which some 790MW is already installed. This total represents approximately 125% of the Walpole grid transformer firm capacity

The reason that the Walpole capacity is significantly higher than that of Enderby is that the Walpole group already includes Peterborough and King’s Lynn CCGT power stations, the generators of which have high inertia constants. The Enderby area currently has negligible embedded generation connected. Future generation has been studied with an assumed inertia constant of 3MWs/MVA (for generation of 50MW and above - see section 3.2), which is considerably lower than the Walpole group CCGT inertias. Thus, the transient performance of the future generators has significantly limited the connection capacity of the network. The capacity of the Enderby group would be considerably increased ifhigher inertia generators were to be installed.

40 Grid Group GSP Firm BSP Firm Capacity by County Comments Capacity (MVA) (MVA) Derbyshire Leicestershire Lincolnshire Northamptonshire Nottinghamshire

Chesterfield 720 390 195 Coventry 720 75 45 Also supplies Warks (360MVA BSP firm capacity) Drakelow 240 45 Also supplies Staffs (75MVA BSP firm capacity) East Claydon 720 45 Also supplies Bucks (270MVA BSP firm capacity) Enderby 4'0 420 Grendon 720 255 570 Ratcliffe-on-Soar 720 90 420 Staythorpe 240 30 135 180 Walpole 720 375 Also supplies Norf & Cambs (390MVA BSP firm capacity) West Burton 240 180 120 Willington 600 630 Also supplies Staffs (45MVA BSP firm capacity)

Table 14 Firm Capacity of Grid Supply Points (GSPs) and Bulk Supply Points (BSPs) in the East Midlands

41 For connections at 33kV and below, the detailed studies have shown that, due to transient stability considerations, very little can be connected in urban areas but approximately 15% of BSP firm capacity can be connected in rural areas.

The remaining grid groups in the region have therefore also been analysed with respect to their firm capacities. The capacity of the network to accept future generation has been calculated by applying the following constraints in each group:

• total generation within a group limited to 50% of group firm capacity, due to transient stability considerations;

• total generation connected to the 132kV network within a group limited to 50% of group firm capacity, due to transient stability considerations;

• total generation connected to each bulk supply point at 33kV limited to 15% of BSP firm capacity in rural areas and zero in major cities (Derby, Leicester, Northampton and Nottingham), due to transient stability considerations;

• future generator connections limited by the spare fault level capacity at 132kV, 33kV, 11kV and 6.6kV substations;

• future generator connections limited by known specific local power flow constraints (eg line thermal rating constraints, transformer tap-changer reverse power flow constraints).

The transient stability constraints are based on the results of the detailed studies of the Leicester (urban) and Boston (rural) areas, with the worst case Leicester result being used for the group total and 132kV constraints. It should be noted that the exact transient performance of the network and generators is highly dependent on the parameters of the individual generators to be installed (particularly inertia constant) and any measures that are introduced to mitigate against adverse performance.

The fault level constraints have been applied across the whole region, at all voltage levels from 132kV to 6.6kV using the results from the latest EME fault level survey, completed in October 2002. The spare fault level margin at each substation has been used to estimate the maximum generation which can be connected.

The spare network capacity for the whole East Midlands region obtained from this analysis is shown in Table 15, broken down by county and by grid group. Note that a small area of north-west Derbyshire is served by Buxton bulk supply point which is owned by United Utilities. A capacity contribution for this network has been estimated and included.

42 Grid Group Spare I etwork Capaciity (MW' Midlands

Derbyshire Leicestershire Lincolnshire East Northamptonshire Nottinghamshire

Chesterfield 49 11 60 Coventry 6 3 9 Drakelow 6 6 East Claydon 7 7 Enderby 0 0 Grendon 0 21 21 Ratcliffe-on-Soar 9 8 17 Staythorpe 2 20 14 36 Walpole 110 110 West Burton 50 49 99 Willington 31 31 Buxton BSP 13 13 TOTAL 99 17 180 31 82 409

Table 15 SpareNetovorkCapacity in theEastMidlands

In order to compare the capacity of the East Midlands distribution network calculated by the above analysis with the targets for renewables and CHP, two assessments have been carried out. In the first assessment, the future development of renewables only is considered ie assuming no growth in CHP. The second assessment considers the simultaneous development of both CHP and renewables. The results are shown in Tables 16 and 17 and Figures 1 and 2 respectively. In each case, the existing generation is added to the calculated spare network capacity to obtain the total potential network capacity which can then be compared with the targets.

43 Generation Capacity (MW)

Derbyshire Leicestershire Lincolnshire Northamptonshire Nottinghamshire Total

Renewables target - 2003 16.8 22.3 14.4 27.1 22 .1 102.7

Renewables target - 2010 74.7 73.8 210.5 68.1 38.4 465.5

Existing renewables 3.0 11.1 9.7 5.0 15.9 44.7

Spare network capacity 99 17 180 31 82 409

see note 1

Total potential network 102 28 190 36 98 454 capacity for renewables

Table 16 Nehvork Capacity for Renewables in the East Midlands compared with Resource Targets

Note 1. May need to be reduced, subject to developments in north Cambridgeshire and north-east Norfolk. Does not include capacity of Yorkshire Electricity network in north Lincolnshire.

44 Generation Capacity (MW)

Derbyshire Leicestershire Lincolnshire Northamptonshire Nottinghamshire Total

CHP target - 2010 331. 6 89.6 65.0 97.1 125.3 708.6

Renewables target - 2010 74.7 73.8 210.5 68.1 38.4 465.5

Total target - 2010 406.3 163.4 275.5 165.2 163.7 1174.1

Existing CHP 297.6 4.6 14.0 12.1 40.3 368.6

Existing renewables 3.0 11.1 9.7 5.0 15.9 44.7

Spare network capacity 99 17 180 31 82 409

see note 1

Total potential network 400 33 204 48 138 822 capacity for renewables and CHP

Table 17 Nehvork Capacity for Renewables and CHP in the East Midlands compared with Resource Targets

Note 1. May need to be reduced, subject to developments in north Cambridgeshire and north-east Norfolk . Does not include capacity of Yorkshire Electricity network in north Lincolnshire .

45 500

450 □ Existing Generation □ 2003 Target 400 □ 2010 Target 350 ■ Network Capacity 300

Cti & 250 u 200 1 g 150 O 100 a n n J 50 _l J ■ r 0 ■ ■ Derbys Leics Lines Northants Notts East Midlands

Figure 1 Network Capacity compared with 2003 and 2010 Targets for Renewables

1300 1200 □ Existing Generation 1100 _ 1000 0 2010 Target 1 ™ ■ Network Capacity ^ 800 700 U 600 5 500 2 yS 400 ^ 300 200 ■ PL 100 ■ 1 FI Pm ■ - _ 0 ] m L , r m Derbys Leics Lines Northants Notts East Midlands

Figure 2 Network Capacity compared with 2010 Targets for Renewables and CHP

46 4.4 Commentary; CountyNeftyorkCapacities andTargets

Figure 1 shows that if CHP development is ignored, the network capacity in each county is sufficient to satisfy the 2003 targets for renewables, but not the 2010 targets. When CHP development is included (Figure 2), there is a deficit of network capacity in every county and a large deficit for the overall region. Consequently, problems will almost certainly be encountered, requiring network enhancements, in achieving the 2010 targets for renewables and CHP.

In interpreting Figures 1 and 2, it is important to understand that the total network capacities calculated for each county are maximum capacities of the existing network. These are only achievable if all proposed generation can be connected (and therefore located in or near) to favourable network areas, ie all of these suitable connection areas must be exploited to their maximum potential. If any areas on the network with spare connection capacity cannot be developed to their maximum potential, then the overall useful network capacity will be reduced.

The spare capacity calculated for the region is unevenly distributed and many constraints exist across the whole network. For example,

• 52% of the 63 bulk supply groups which serve the region at 33kV and below cannot accept any additional embedded generation at all.

• Only 10% of bulk supply groups have a spare capacity above 10MW.

In addition, connections to 11kV networks and below may entail significant works to meet transient stability requirements.

In practice, the locations of generation developments will be determined primarily by other constraints such as land issues (eg use, availability, planning) and fuel resource/supply. Sites are not usually selected simply because they are near to a suitable grid connection point. Consequently, it is unlikely that all of the good network connection areas will be developed, either to all or part of their full potential. ft should therefore be expected that the useful network capacity will be reduced somewhat compared with the maximum network capacity calculated.

Conversely, it is likely that several generation schemes will be proposed in areas of low or zero network capacity, thereby necessitating works to reinforce or enhance the network. fn order to minimise the number of such proposed schemes, the network capacity should be significantly in excess of the targets and, more importantly, have a high proportion of connection points which are unaffected by constraints.

47 A summary taking into account the distribution of the spare network capacity within each county is given below.

Derbyshire

The network capacity exceeds the 2010 target for renewables only, but not including CHP. The spare capacity in Derbyshire is basically provided in north Derbyshire, around Chesterfield, Heanor, Winster (in the Peak District) and Buxton. There is very little capacity in south Derbyshire except for a little at Stanton near flkeston and also Swadlincote near Burton-on-Trent. Significantly, there is no spare capacity in Derby itself. This is therefore likely to impact on many proposed projects in these areas, including the energy from waste scheme for Derby.

Leicestershire

The 2010 targets for Leicestershire appear to be moderate; however, the network in Leicestershire is severely restricted by the fault level limitations in the Enderby group and the Leicester area, affecting connections at all voltage levels from 132kV to 11kV. The only spare capacity is available in the Loughborough and Hinckley areas but this is insufficient to meet the 2010 targets, for either renewables or CHP, and further, many of the predicted projects are likely to fall outside these areas.

Lincolnshire

fn Lincolnshire, the studies show that the available network capacity is insufficient to accommodate the 2010 targets, which are comprised primarily of offshore and onshore wind plus CHP. The south-eastern corner of the county, including Boston, Skegness, Spalding, Bourne and Stamford, is served by Walpole grid group and has been studied in detail (see chapter 3). Although this group has a large capacity, it is highly utilised by the existing CCGTs at Peterborough and King’s Lynn. The remaining capacity of this group is therefore only 110MW. ft should be noted that this group serves East Midlands Electricity (Lincolnshire) and Eastern Power Networks (Cambridgeshire and Norfolk) in roughly equal proportions and therefore this spare capacity ought to be divided similarly between these two areas. However, for the purposes of illustrating what is feasible for Lincolnshire, the whole of this spare capacity has been allocated to this county. Additional spare capacity for Lincolnshire is provided by the network around Lincoln, Grantham and Sleaford. Developments in north Lincolnshire (eg at Louth, Market Rasen, Gainsborough, Cleethorpes, Grimsby and Scunthorpe) would be covered by the Yorkshire Electricity network, which may be able to provide additional capacity, thus enabling the 2010 targets to be met.

48 Northamptonshire

Spare network capacity in Northamptonshire is low because a large CCGT power station at Corby already exists.

The 2010 targets are relatively modest but still cannot be accommodated by the existing network. There are network restrictions covering some key development areas in this county, including Northampton and Corby, and therefore it is highly probable that proposed development sites will not coincide with the areas of available network capacity. Consequently, it may be expected that several projects in Northamptonshire will necessitate system reinforcements. The spare network capacity is fairly evenly distributed between Kettering, frthlingborough, Wellingborough, Brackley and Daventry.

Nottinghamshire

The 2010 target for renewables only is very low and could theoretically be accommodated by the network. However, when CHP is included, the network capacity is not sufficient.

The network in Nottinghamshire is served by four different grid groups (Chesterfield, Ratcliffe, Staythorpe and West Burton) and these provide spare capacity mainly in the north of the county around Worksop, Retford, Mansfield and Newark. There is also a little capacity provided in the extreme south of the county at Willoughby on the Wolds, which could be shared with Leicestershire. The largest restriction is that there is no spare capacity in the Nottingham area. Although the available spare capacity is reasonably well distributed, it is limited in magnitude due to fault level and transient stability constraints.

49 5 ENHANCEMENT OF NETWORK CAPACITY

This chapter discusses the various technical issues which result in constraints on the connection of embedded generation, together with possible solutions.

5.1 Summary of Generation Constraints and Potential Solutions

A summary of the network constraints which are most commonly encountered in assessments of generator connections is given in Table 18 below.

Connection Point Common Network Constraints Urban areas Rural areas 11kV circuits Fault level Voltage rise Transient stability Voltage step change Thermal rating Transient stability 11kV primary Fault level Voltage rise substations Transient stability Thermal rating Transient stability 33kV circuits Fault level Voltage rise Transient stability Voltage step change Thermal rating Transient stability 33kV BSP Fault level Transient stability substations Transient stability 132kV network Fault level Thermal rating Transient stability

Table 18 Summary of Common Netorork Constraints Relevant to Generator Connections

It should be noted that the above table is only indicative of the occurrence of network constraints and that other constraints may occur in individual cases. For example, fault levels are generally lower in rural areas than in urban areas due to lower transformer capacity and long overhead lines. However, fault level problems could still occur in rural areas where a substation has a particularly low fault rating.

Potential solutions to these problems, as discussed in the next section, are summarised in Table 19.

50 onstraint Potential Solutions Fault level • Replace or upgrade plant to increase ratings • Install high impedance plant (eg generators, transformers, reactors) • Sectionalise the network by opening switches such as bus-sections or transformer incomers (with auto close schemes to restore supplies after trips) • Fault current limiters (possible future development)

Transient stability • Relax requirement for generator to remain connected following network faults (positive generator tripping will be required; predictive pole-slip protection relays may assist in future) • Improve network fault clearance times • Improve power factor of asynchronous machines • Improve generator inertia • Power system stabilisers to damp oscillations exacerbated by low inertia • Install compensation devices in weak areas of the network (eg SVCs) • Generator braking resistors (future development)

Voltage rise • Reduce voltage at source substation (eg primary or BSP) - subject to effect on other users • Import of reactive power by the generator • Replace circuit with larger conductor (reduced resistance) • Install booster transformer with AVC between generator and source substation • Connect generator to source substation by a dedicated circuit • Automatic voltage control scheme to reduce generator reactive and active power output as necessary (eg low load conditions)

Thermal rating • Replace conductor • Reprofile line (132kV and above) General • Connect to a higher voltage level

Table 19 Summary ofPotential Solutions toConstraints

51 5.2 Discussion ofGenerationConstraints andPotential Solutions

Fault Levels

The term “fault level” refers to the short-circuit current which flows in the event of a short-circuit fault in an electrical network. Short-circuits occur following failure of the insulation in an item of plant. This may be due to insulation which is defective or has deteriorated through age, or due to damage from external actions, for example, damage to insulation of an underground cable caused by mechanical excavation, or a branch of a tree falling onto bare overhead line conductors and bridging the insulation (air) between them.

Fault levels may be considered to be one of, if not the, most important constraining issues relevant to the connection of embedded generation. It is a safety issue and is enforced by health and safety legislation. Regulation 5 from the Electricity at Work Regulations 1989 concisely states the fundamental requirement:

“No electrical equipment shall be put into use where its strength and capability may be exceeded in such a way as may give rise to danger”.

This regulation actually applies to all of the operating conditions which may be imposed on an item of plant, including the full range of normal load currents and voltages as well as transient conditions such as short- circuit faults. However, strict attention is normally given to short- circuits due to their catastrophic nature and serious consequences whereby a fault may occur without warning, instantly creating a risk of serious injury or fatality.

The regulation is absolute and must therefore be met regardless of cost or any other consideration. All reasonable steps must be taken and all due diligence exercised to avoid breaching the regulation. Thus a risk assessment approach to management of fault levels is generally not favoured. It is interesting to note that the regulation is qualified by the words “in such a way as may give rise to danger”. This implies that it is not an offence for fault levels to exceed plant ratings providing there is no risk of danger. Therefore, management of excessive fault levels by prohibiting personnel from working near to at-risk plant may occasionally be employed. However, such control measures can be very difficult to implement and guarantee, whilst continuing with normal operation and maintenance activities. Also, it may be difficult to completely segregate plant on extensive distribution networks from the public.

Consequently the preferred strategy is to ensure that ratings of plant at all points on the network are suitable for the worst case prospective fault levels. The plant also needs to be maintained such that its strength and capability is not unduly impaired with age.

52 Almost all items of electrical plant have a rated capability to withstand short-circuit currents, including cables, busbars and disconnectors. Circuit breakers are normally of most concern because as well as withstand capabilities, they also have to be capable of fault switching duties - both making (ie closing onto a fault) and breaking of fault currents. In addition to the onerous nature of these switching duties, the act of normal circuit switching (ie load switching) presents a risk that the switching operation itself may initiate a short-circuit fault eg if equipment is faulty or if a maintenance earth has not been removed. For this reason, remote operation of circuit breakers is preferred. Transformers are not normally a concern as they are designed to withstand the maximum fault current which can flow through them as limited by their internal impedance.

In existing transmission and distribution systems, the sources of virtually the whole short-circuit current are rotating machines: generators are the most important, but motors also provide significant contributions which need to be taken into account. The addition to a system of rotating generators (synchronous or asynchronous) always places more onerous fault duties on existing plant. The magnitude of the short-circuit current is increased but also the characteristics of the fault current decrement are changed such that normal test characteristics used for standard distribution circuit breakers may no longer be suitable.

The basic fault level problem specific to distribution systems in Great Britain is that because they have not previously been designed to accommodate embedded generation, the fault ratings of switchgear are relatively low. Conversely, fault levels have risen over the years due to the recognition of motor infeeds, the introduction of additional and/or higher rated, lower impedance plant (eg transformers) to supply increasing load, and the gradual penetration of embedded generation. Consequently there are many substations where existing fault levels are close to plant ratings and no or very little margin is left. Hence, the present drive to introduce more embedded generation is resulting in many cases where prospective fault levels could exceed plant ratings unless corrective action is taken.

Typical fault ratings of many existing distribution circuit breakers are, for example:

• 13.1kAat11kV

• 13.1kA or 17.5kA at 33kV

• 10.9kA or 15.3kA at 132kV

These are old specifications and are no longer used; however there is a large proportion of circuit breakers in existing networks which have these ratings. Fault level problems may very easily arise with such low ratings.

53 Modern ratings that are now typically specified for distribution systems are as follows:

• 20kAat11kV

• 20kA or 25kA at 33kV

• 20kA, 25kA or31.5kAat 132kV

To put these into context, the following substantially higher ratings are normally seen in transmission systems and power station auxiliary systems, in which the circuit breakers are near to high levels of rotating generators and/or motors:

• 25kA to 50kA at 11kV

• 31.5kA* and 40kA* at 132kV

• 31.5kAand 40kA* at 275kV

• 50kA or 63kA* at 400kV

• indicates current NGC standard rating

One further characteristic of network fault levels which extends their importance is that their influence is not locally confined but is far- reaching. Thus, connection of generation will raise the network fault levels not just at the point of connection but at all points over a wide area. This reach can extend across transformers to increase fault levels at higher or lower voltage levels. The same concept can be applied when considering the constraints imposed by a highly stressed item of network plant. For example, a high fault level at a single switchboard may result in generation constraints over a wide area and at several voltage levels. It can readily be seen that a handful of fault level problem locations can quickly result in a large area being blanketed by several layers of problems - any proposed connection point faces several problems all of which must be resolved.

Network planning engineers frequently face a major problem in establishing “where to draw the line” in determining the relationship between a fault level constraint and distant generation. For example a problem at a 132kV substation might be aggravated by any generation connected in the whole of that group, even if connected two voltage transformations away, at 11kV. A single small generator (eg 1MW) connected two transformations away may cause an immaterial increase in the fault level; on the other hand, many such generators may collectively have a significant effect.

The options to solve fault level constraints in existing networks are to increase ratings by plant replacement or refurbishment, or various options to reduce and contain fault levels below the existing ratings.

54 All of the latter options suffer from the drawback that there is conflict between low fault levels and power quality. The lower the fault level, the more problematic are issues of generator and network stability, voltage regulation and control, voltage fluctuations and harmonic distortion. Reliable operation of protection schemes can also be difficult to achieve where fault levels are constrained at abnormally low levels. The disadvantage of plant uprating is the high cost typically involved, especially as there may be a knock-on effect on plant at other sites in the area. Its advantage is that it is a fit-and-forget solution which allows network and generator operation under a wide range of conditions without the need for constraints. Occasionally it may be possible to avoid a fault level problem by connecting to a higher voltage level.

Assuming that the current strategy to encourage increasing levels of embedded generation continues, it is considered that the low distribution fault ratings quoted above are simply too low to accommodate such embedded generation without undue difficulty (eg non-standard plant specifications and operating arrangements would be required) and without unduly compromising the security and quality of supply of the system. The existing network will therefore impose constraints on proposed generation at too many locations, severely reducing flexibility in development. The practices developed in the transmission system design to accept generation now need to be applied to the distribution system.

Hence, it is recommended that the design fault levels (ie ratings) of distribution networks be increased to levels appropriate to the predicted expansion of embedded generation. The following rating increases are recommended:

• 25kA at 6.6kV

• 20kA or preferably 25kA at 11kV

• 20kA or preferably 25kA at 33kV

• 25kAor31.5kAat132kV

Higher ratings may be justified at some sites, depending on future embedded generation targets.

The choice of 25kA as a standard rating represents a reasonable compromise between a design fault level that is too low and one that is too high. The disadvantages of increasing the design fault level to more than this are that there would be a greater knock-on effect on downstream plant, thus increasing cost, and that the energy in a higher fault current presents a greater risk of danger to personnel and plant.

Plant uprating could be performed on a progressive basis, such that after several years, the network is substantially upgraded to a 25kA

55 system. The sites to be targeted first would be those where fault levels are already close to ratings, where generation is to be installed, or where plant is reaching the end of its life. The disadvantage of uprating any other sites would be that a high cost would be incurred without any real benefits. It is therefore not cost-effective to uprate some parts of the network without knowledge of firm generation proposals there.

The alternative solutions to reduce and contain fault levels are well known and should still find application in the future in certain individual cases.

• Use of generator or network plant with higher than normal impedance, including installation of reactors.

• Reconfiguration of the network eg by opening bus-section switches or switching out transformers onto hot standby (when they can be quickly switched in again if required). This option is normally to the detriment of security of supply.

The other solution to contain fault levels is the use of fault current limiters. Existing devices have been available for several years which break fault current by means of an explosive link and a conventional fuse in parallel. This provides extremely rapid fault interruption, before the fault current reaches its prospective peak value. The fault currents seen by other network plant (eg circuit breakers) are therefore reduced. These devices have been used in Europe and in the UK in private (eg industrial) networks. However, they have not been accepted by most utilities in the UK because of concerns over their reliability.

Alternative designs of fault current limiters using superconductors are currently being developed. These limit fault current by becoming high impedance in response to increased temperature due to the fault current itself. It is therefore claimed that they operate as a fail-safe design. Prototype devices have been built and tested, although commercial designs in the ratings required in the power industry are still some years away.

Transient Stability

As with fault levels, transient stability is also of major concern in system planning because it is a potential problem which applies to a great many sites over most of the network, rather than being confined tojust a few problem sites. Firstly, this problem applies to virtually all generator connections to any point on the 11kV network. Secondly, it applies to large portions of the 33kV network. At the 132kV level, the problem is generally less abundant, but may still be the factor which limits the acceptable generation at several sites. The consequences of instability are also more severe for a generator connected at 132kV

56 than one connected at 11kV, in that the former would create disturbances seen across a wider area of the network.

The effects of instability are possible damage to plant, especially generators and motors, due to severe mechanical and thermal stresses, and poor quality supplies or even total loss of supplies to distribution system users. This may be compounded by cascade tripping of generating plant, threatening widespread system instability and collapse.

Section 3.3 in this report describes the background of the transient stability problem and explains that the two most important factors which contribute to a stable system are fast fault clearance times and high generator inertia. The significance of these two factors is illustrated in Figures 3 and 4 which are based on example case simulations of synchronous generators.

Figure 3 shows the maximum generation which can be connected, without instability, for various network fault clearance times and generator inertia constants (H). Firstly, it can be noted that inertia constant does have a large effect on the maximum stable generation which can be connected. For example, assuming a fault clearance time of 150ms, the generation capacity may be increased from 20MW to 115MW by doubling the inertia constant from 1.5MWs/MVA to 3MWs/MVA. However, it is important to note that the inertia constant is only relevant for fast clearance times. As the fault clearance time is increased, the maximum stable generation reduces rapidly - the 115MW of acceptable generation for an inertia constant of 3MWs/MVA and 150ms clearance time is reduced to 0MW if an additional 100ms is introduced into the fault clearance time. For fault clearance times of greater than 350ms, the inertia constant is not relevant (assuming values within the normally encountered range): it is not possible to connect any stable generation.

The case study illustrated in Figure 4 considers the connection of small (10MW), medium (50MW) and large (100MW) generators to a 33kV network, where the existing fault level is 750MVA. These represent short circuit ratios of 75, 15 and 7.5 respectively (the results may be applied, approximately, to other connection point and generator combinations having similar ratios). The critical clearance time is calculated for each generator as the inertia constant is varied. Again, it can be seen that even in the best case (smallest generator, largest inertia) the critical clearance time is less than 350ms and reduces to around 100ms as the inertia constant is reduced.

57 S. 200 «— 11-3

H=1

.5 50

Actual clearance time (ms)

Figure 3 Effect of Actual Clearance Time and Inertia Constant (H) on Maximum Stable Generation (synchronous generators)

-A— 10MW

50 100 150 200 250 300 350 400 450 500 550 600 650 700 750 800 850 900 950 Critical clearance time (s)

Figure 4 Effect of Generator Maximum Output and Inertia Constant on Critical Clearance Time (synchronous generators)

58 The effect of either increasing the generator size, or reducing the fault level provided by the network at the connection point, is to move the line of critical clearance times to the left, thus eating into the margin (if any) between critical and actual fault clearance times.

It is interesting to compare these results with typical cases of generator connections to transmission and distribution networks. Conventional large generating units connected to the transmission system typically have inertia constants in the range 4 to 7MWs/MVA. Further, the protection systems on the transmission system have very fast operating times, giving fault clearance times in the range 80 to 150ms. Such connections would therefore lie in area T shown in Figure 4 ie on the stable side of the critical clearance times.

However, in the case of the distribution network, fault clearance times are typically in the ranges 0.5 to 1s on the 11kV network and 0.2 to 1s on the 33kV network. Also, the trend in new connection applications for small generating units has been for very low values of inertia constant eg values of 2 or 1MWs/MVA or even lower are frequently seen. These cases are very firmly in area D shown in Figure 4. Thus, stability is almost impossible to achieve for 11kV connections, and frequently very difficult for 33kV connections.

The problem of stability is therefore considerably more difficult in the case of distribution systems than for conventional generators connected to transmission systems. Not only is the former starting with considerably slower fault clearance times, but even if these were improved, it is being asked to accommodate generators which, because of their low inertias, are inherently less stable.

The easiest action which can be taken to address the stability problem is to relax the planning requirements, wherever possible. These requirements, which state that generators should have a fault ride- through capability for a specified range of credible network faults (ie they should remain connected to the network without tripping or causing instability or pole-slipping), were included in old CEGB planning standards and are still used by transmission system operators today. The requirements were adopted, with minimal changes in distribution system planning policies and included in Engineering Recommendation G75. The requirements are not explicitly stated but are implied by Engineering Recommendation G59.

Relaxing the requirements would effectively allow the generator to trip in response to certain network faults. This policy has actually been implemented over recent years with regards to several small synchronous generator schemes and most wind farms. The key requirement then becomes to ensure fast and reliable generator tripping for defined network faults, before pole-slipping or instability can occur, but to avoid excessive nuisance tripping due to normal power swings. In the case of wind farms, tripping is reliably achieved by undervoltage protection before any adverse effects, such as

59 overspeeding, occur. However, with synchronous machines, undervoltage protection is often time-delayed and may not operate in response to a network fault. There is therefore a risk that the generator will pole-slip one or several times before tripping. It is therefore recommended that pole-slipping is prevented by a reliable protection tripping scheme such as direct intertripping following operation of relevant network protection, or fast acting undervoltage protection. The disadvantage of the latter is that it may also respond to less onerous network disturbances, which would not result in pole-slipping, thus increasing nuisance tripping.

In any event, pole-slip protection should be fitted to positively disconnect synchronous generators as rapidly as possible should pole­ slipping occur. Conventional pole-slip protection should be seen as a back-up protection, the primary aim being to design the connection and the main protection scheme to prevent pole-slipping in the first place. Traditionally, pole-slip protection has been viewed as warranted only for large, expensive generators. However, due to the high risk of pole­ slipping of embedded generators and the increased number of such machines, it is recommended that pole-slip protection should be specified on all synchronous generators.

A development which may become available in the next few years is predictive pole-slip protection. The objective of these relays is to identify the occurrence of network disturbances which commit the generator to pole-slipping, and then to rapidly disconnect the generator before the worst case conditions of a pole-slip actually occur. Thus, the relay aims to achieve the two key, but often conflicting requirements of fast operation and stable or reliable operation. Such schemes are currently being developed and tested.

There are several issues which need to be carefully considered in relation to the policy of relaxed stability standards. Firstly, and perhaps most likely, the policy has implications for the generator. The generating unit (whether synchronous or asynchronous) will be at risk of increased tripping, due either to network faults, possibly over a large catchment area, or to nuisance tripping in response to power swings. Regular tripping from a highly loaded condition, and pole-slipping in the case of synchronous generators, will have a detrimental effect on the availability and energy yield, wear and tear, maintenance requirements and ultimately the life of the generator and its prime mover. Consequently, it is recommended that these implications of relaxed stability standards be discussed and agreed between the network operator and the generator.

The implications for the network operator are that it is necessary to monitor the quantity of generation which may be tripped following any single fault incident. At present, it is unlikely in most cases that the loss of a single, say, 5MW generator due to a network fault will create any detrimental effects for the network or other users, providing the generator is rapidly tripped before it comes close to pole-slipping. The

60 opposite scenario in the future could involve a single network fault causing the loss of many generators and of a significant total power infeed. This could consequently result in a large disturbance to the network, most likely as a voltage disturbance, but possibly as a frequency disturbance. The likelihood of this is increased if additional generators become affected due to network instability and cascade tripping. Hence, it is likely that a threshold will exist in terms of the maximum quantity of generation which can be tripped in response to any single network fault, without giving rise to network instability. Monitoring is therefore required to ensure that improvement plans can be developed if this threshold is approached.

Reduced stability standards may also impact on proposals to include embedded generation in security of supply assessments. Although some embedded generation may be quickly restarted following a trip and therefore provide a contribution within the specified restoration times, this may not be true for all generators. In any case, generation which has tripped cannot be counted towards immediate supply of load.

The alternative approach which can be taken to address the stability problem is to work towards the full application of the existing stability standards by improving the transient performance of generators. The benefits of this are primarily for generators in that they will be subjected to a smaller risk of pole-slipping and/or tripping and also consequently have a higher availability grid connection. The network will also be at less risk of power quality problems and would be able to enjoy more reliable support from generators towards security of supply, thus partially alleviating the need for reinforcement to meet future load growth.

The options to improve transient performance fall into two main areas: improvements to the network and improvements to the generating plant. On the network side, by far the most significant improvement which can be made is to improve fault clearance times. This would primarily involve replacement of existing IDMT (inverse definite minimum time) protection schemes with fast-acting schemes such as unit protection and distance protection. This is not a cheap option as many substations and circuits would need to be included. This is the approach which is taken on the transmission system, and will almost certainly need to be applied in the case oflarge embedded generators.

Occasionally, voltage stability problems, arise when generators are to be connected to weak networks, remote from grid supply or bulk supply points. Improvements are possible by the installation of additional voltage support, through reactive compensation devices ie capacitors, SVCs or other FACTS devices.

On the generator side, there are two options which should be considered for further development by manufacturers. The first is to increase the inertia of the generator and prime mover, either by

61 increasing the mass of core rotating components or adding a flywheel. This obviously will increase the cost of generators but may be more cost effective than the necessary improvements to the network. In view of the importance of inertia to stability and power quality, consideration should be given to introducing a minimum value of inertia constant in connection conditions, similar to the specification of minimum generator short-circuit ratio.

The second future development is the use of generator braking resistors. These would be normally bypassed but switched in under fault conditions. The braking resistors would be connected in series and would use the fault current supplied by the generator to dissipate power from the prime mover, thus controlling acceleration. The resistors would be switched out following clearance of the fault and would therefore only need to have a short-time rating.

The most effective way of improving stability of present generation schemes would be to constrain output. This would only be acceptable as a temporary measure, otherwise yield will be unduly affected, but it might be considered in cases where stability is a problem only under a few rare network configurations.

The performance of asynchronous machines can be improved by increasing their reactive compensation. This reduces the reactive demand on the network and improves voltages in weak networks. In the case of conventional asynchronous generators, increased reactive compensation would be achieved by additional capacitors. The double-fed induction generators which are now being marketed, have the ability to achieve full compensation (ie export at unity power factor) and in some cases also provide a reactive power export capability. Dynamic modelling of these machines is currently being addressed by academia and industry and initial impressions are that the transient performance will be superior to that of conventional machines. Similar improvements can be made by increasing the excitation of synchronous generators, which will result in increased generator terminal voltage and/or increased reactive power export. This may be undesirable, either for technical (eg voltage rise) or commercial reasons.

Power system stabilisers are devices which detect oscillations in the power output of a generator, due to generator rotor swinging, and provide compensating feedback via the generator excitation system. They do not significantly reduce the risk of pole-slipping, but are used to improve the damping of oscillations caused by synchronous machines. Such oscillations are prominent in machines of low inertia and will degrade the power quality of supplies to other users. Therefore, the widespread use of power system stabilisers on embedded generation, especially low inertia units, should be considered.

62 The advantage of generator improvements is that they all provide inhibitive or corrective action at the source of the problem ie at rotating machines, and are thus more effective than solutions applied remotely on the network.

Voltage Rise

Voltage rise occurs when excessive generation is connected remotely from voltage control points in the network. Voltage control points are usually busbars at grid supply points, bulk supply points and primary substations where voltage is controlled by transformer on-load tap changers. Generation which is connected remote to such substations, via existing overhead lines or cables, will, if excessive compared to the local load, export surplus power back to the supply substation. This export will cause the voltage at the generator to rise above that of the supply substation. There is then a risk that supplies to users, including the generator’s installation, may exceed the statutory upper voltage limit.

The voltage rise problem therefore originates from excessive generation relative to the strength of the network and insufficient voltage control points in the network.

Although voltage rise is a widespread problem, it does not usually apply to generators connected close to major busbars (GSPs, BSPs and primaries). At these sites, the supply transformers, with automatic on­ load tap changers, normally have sufficient tapping range to control the busbar voltage, even if a large reverse power flow through the transformer occurs. The main issue is then to ensure that the tap changer itself is not designed for switching between taps only when the power flow is from the high voltage to the low voltage side. This may apply to some older designs and it may be possible to replace these on some transformers.

Several solutions to voltage rise are available and are presently practised. The first consideration is often to investigate the target control voltage at the source substation and reduce if possible. This is normally limited by the need to consider voltage drops seen by remote users under maximum load conditions and when the generator may not be running. The voltage at the source busbar therefore has to be tightly controlled, as there may be no further downstream voltage control points, and the control scheme must provide satisfactory results over a wide range of conditions, from minimum load to maximum load. The addition of generation effectively doubles the range of conditions which have to be accommodated by the control scheme.

The generator may be able to operate at a leading power factor ie to import reactive power from the source substation. This is an effective way of reducing the voltage rise as the import of reactive power produces a voltage drop which cancels out the voltage rise caused by the export of active power. Wind turbines using conventional

63 asynchronous machines normally import reactive power and are therefore less prone to voltage rise problems than synchronous generators.

This option is undoubtedly viable in many individual cases, although there is the drawback that leading power factor operation reduces synchronous generator stability margins. If this is a problem, then a shunt reactor or SVC at the generator site may be considered to allow import of reactive power whilst maintaining high excitation (lagging power factor) on the generator itself.

The other potential disadvantages of this solution, if applied on a widespread scale, are that it places increased demand on the upstream suppliers of reactive power (ie large generators and reactive compensation plant) and increases losses in the network. These may, however, turn out to be acceptable. Firstly, providing automatic control is used (described below), the increased reactive demand occurs at times of low load, which is exactly when large generators have spare capacity to export reactive power if required. Secondly, increased losses can be tolerated if increased use of renewables and their free or low cost fuel supplies is made. Revisions to the settlement system would probably be required to ensure that network operators are not penalised by any increased losses resulting from this option.

Where reduced busbar voltage and leading power factor operation are not acceptable, there are options to reinforce the network. These include replacement of the circuit between the generator and the supply substation using larger conductors (with lower resistance), or installing a new dedicated circuit, suitably sized, to connect the generator all the way back to the source substation. The latter has the advantage that there are no existing customers supplied from it and therefore the voltage control along that circuit can be relaxed to some degree.

An alternative to circuit reinforcement is to install a booster transformer with on-load tap changer in the circuit, to provided an additional voltage control point. This can correct for voltage rise under all load and generation conditions by selecting the appropriate tap. Depending on the length of the circuit, a booster transformer may be cheaper than circuit replacement and simplify planning procedures.

Connection studies normally assume unconstrained output from the generator and therefore consider the worst case condition of maximum generation with minimum network load. This condition frequently results in onerous results for voltage rise and thermal loading. The maximum generation which can be accommodated is therefore often limited to that which, at full output, will give satisfactory performance with minimum load. These problems could be significantly reduced by controlling and constraining the generator output as necessary. From a network perspective, the optimum use of existing assets would be made by regulating the generator output to follow, approximately, the local load. This would then enable a considerably larger generator to

64 be connected, operating at full output at times of high load and constrained down as the load falls. Thus the total yield at a given connection point would be significantly increased although the larger generator itself would operate at a low load factor.

A current development which may be used regularly in future is automatic control of generator output in response to the network voltage at the connection point. When the upper voltage limit is reached, the control scheme would attempt to control this by firstly importing reactive power from the network, as described above (or reducing export of reactive power). When reactive power limits are reached, the generator active power output could then be automatically reduced to keep the network voltage within limits (at distribution system voltages, especially 33kV and below, network X/R ratios are low and therefore active power flows do have a large effect on voltage rise). These constraints would only apply when the upper voltage limit is reached. Hence, at times of low load, the generator output would be automatically reduced, as necessary, with no long distance communication required. At times of high load, it is worth noting that the generator would also provide useful voltage support for the network, automatically if required.

Reducing generator output is also very effective in improving stability and there may be limited scope to apply this measure in cases where stability is a concern under particular network operating configurations (eg outages).

Voltage Step Change

Voltage step change need not necessarily limit the total generation which may connect at a connection point, but does limit the total generation which may be tripped by a single generator or network circuit breaker. Actions which can be taken to reduce voltage step change are generator operation at leading power factor or circuit uprating as described above.

Thermal Overloads

Thermal overloading may occur when the generator output is excessive compared to the local load, resulting in a large flow of power back up the network. This may be compounded if the generator is exporting or importing a significant quantity of reactive power as this also contributes to conductor heating.

At the lower voltages (eg llkV and 33kV), circuit capacities are normally increased by replacing the circuit using larger conductors (with lower resistance). In many cases, especially on the llkV network, the conductor size changes frequently and it may only be necessary to replace short sections of line which are made up of the smallest conductor sizes. At l32kV, uprating may be achieved either by conductor replacement or by overhead line reprofiling (increasing

65 the line tension to allow operation at a higher temperature without excessive sag).

General

In addition to the items discussed above, connecting to a higher voltage level may solve most or all of the common network constraints. This will provide a stronger connection (ie higher fault level) for the generator which will improve transient stability, voltage rise and voltage step change. Fault clearance times should also be improved which will improve transient stability.

5.3 Network Improvement Scenarios

Studies have been performed to investigate the potential increase of network capacity to accept embedded generation which could be obtained by various network improvements. Four scenarios of successive network improvements have been considered, in the following sequence:

Scenario l: First stage of transient stability improvements

This scenario shows the level of embedded generation which can be accommodated by relaxing the fault ride- through stability requirements. Embedded generation would need to be equipped with suitable protection to ensure rapid tripping to prevent instability or unacceptable power quality.

Scenario 2: As scenario l plus selected fault level upgrades

Fault level upgrades have been identified at numerous substations across the network and these are detailed in Table 20. These are sites where the existing fault level is close to the substation rating, thereby imposing severe constraints on generator connections over much of the network. The fault ratings quoted are the minimum required: higher fault ratings will bejustified in many cases to provide greater capacity for future developments, at marginal extra cost.

Scenario 3: As scenario 2 plus second stage of transient stability improvements

This scenario includes measures to provide satisfactory performance with total embedded generation up to l00% of GSP or BSP firm capacity. These measures would primarily be based on improving protection on the 33kV and llkV networks to provide faster fault clearance. Generator improvements focussed on inertia,

66 braking resistors and temporary output constraints may also be able to contribute towards these increases.

Scenario 4: As scenario 3 plus power flow upgrades

In this scenario, a few network thermal constraints are removed, by uprating two l32kV double circuits and replacing a transformer tap changer. This enhances the total capability within two grid groups and gives a slight improvement compared with scenario 3.

The enhanced network capacities for CHP and renewables, delivered by the successive implementation of the above improvements, compared with the 20l0 targets, are shown in Table 2l and Figure 5. These capacities are the total potential network capacities, with existing generation included.

The first stage of transient stability improvements does allow more generation to be connected and the total connection capacity within the East Midlands increases significantly (by 80%). Most importantly, this scenario will make many llkV and 33kV connection points available in all areas of the region and therefore greatly increase the flexibility of generation location and distribution. However, there are still deficiencies in Leicestershire and Lincolnshire which need to be addressed.

The fault level upgrades also remove constraints within several areas and consequently provide an additional 88% increase of total network capacity compared with the existing network capacity. The capacity in Leicestershire is significantly increased and should now allow the 20l0 target to be met. The additional capacities quoted in Table 20 include the effects of relaxed transient stability standards as well as fault level upgrades.

The second stage of transient stability improvements, by a combination of network and generator improvements, also gives significant increases: an additional l52% of existing network capacity compared with scenario 2. The studies have shown that the most effective increases are obtained when both fault level and transient stability improvements are implemented in a co-ordinated manner. If only one of these improvements is made, then approximately only half of the full benefit is realised due to the constraint imposed by the other factor.

In the final scenario, only small increases are made through two local upgrades to remove power flow constraints. The first of these, to upgrade two l32kV circuits in the Corby area is, however, recommended as it removes a constraint affecting a large downstream area. Thus, it significantly improves flexibility without greatly increasing the total network capacity. The second upgrade, to replace tap changers at Annesley BSP would similarly remove a constraint affecting the downstream 33kV and llkV network.

67 Grid Group Substation Uprating Capacity Added (minimum requirements) (MW)

Chesterfield Chesterfield 132kV to 25kA 267 Blackwell 11kV to 20kA

Annesley 11kV to 20kA

Goitside 33kV to 25kA

Sheepbridge 11kV to 20kA

Acreage Lane 11kV to 20kA Coventry Coventry 132kV to 25kA 78

Rugby 132kV to 20kA

Hinckley 11kV to 25kA

Hinckley 33kV to 20kA Whitley 33kV to 20kA

Drakelow Burton 132kV to 20kA 40

East Claydon Stony Stratford 52

Enderby Leicester 132kV to 20kA 233 Wigston 132kV to 20kA Coalville 33kV to 20kA

Coalville 11kV to 20kA

Leicester 11kV to 20kA

Redcross St 11kV to 20kA

Leicester East 33kV to 25kA Thurmaston 11kV to 20kA

Thurnby 11kV to 20kA

Salutation 6.6kV to 25kA

Stoneygate 6.6kV to 25kA Leicester North 33kV to 25kA

Leicester North 11kV to 20kA

Birstall 11kV to 20kA

Lero 6.6kV to 25kA

Table 20 Proposed SwitchgearUpgrades

Continued ...

68 ... continued

Grid Group Substation Uprating Capacity Added (minimum requirements) (MW)

Grendon Corby No. 2 llkV to 20kA l56 Corby Central llkV to 20kA

Rushden l lkV to 20kA

Field St llkV to 20kA Northampton l lkV to 20kA

Wellingborough Rd llkV to 20kA

Kingsthorpe llkV to 20kA

Northampton West llkV to 20kA

Wigston llkV to 25kA Whetstone llkV to 20kA

Ratcliffe Nottingham l32kV to 20kA 299 Wollaton Rd llkV to 20kA

North Wilford llkV to 20kA

St Anns llkV to 20kA Sneinton llkV to 20kA

Gedling llkV to 20kA

Marlborough Rd llkV to 20kA

Toton 33kV to 20kA Toton llkV to 20kA

Staythorpe Clipstone 33kV to 20kA 70

Walpole Spalding 33kV to 20kA 0

Park Road llkV to 20kA

Ketton Cement llkV to 20kA West Burton Checkerhouse 33kV to 20kA 0

Willington Willington l32kV to 25kA l75

Spondon l32kV to 20kA

Osmaston Road llkV to 20kA

Derby South 33kV to 25kA Allenton l lkV to 20kA

Normanton llkV to 20kA

Sinfin Lane llkV to 20kA

Table 20 Proposed SwitchgearUpgrades

69 BSP groups Generation Capacity (MW) with no Derbys Leics Lincs Northants Notts Total spare capacity

CHP target - 20l0 33l.6 89.6 65.0 97.l l25.3 708.6

Renewables target - 20l0 74.7 73.8 2l0.5 68.l 38.4 465.5

Total target - 20l0 406.3 163.4 275.5 165.2 163.7 1174.1

Existing network capacity 400 33 204 48 l38 822 52%

Plus TS upgrades (lst stage) 567 ll5 264 225 307 l477 24%

Plus FL upgrades 79' 378 255 285 483 2l98 l0%

Plus TS upgrades (2nd stage) ll54 683 36l 396 855 3448 l0%

Plus power flow upgrades ll54 7l5 36l 439 886 3554 0%

Table 21 Enhanced Nehvork Capacity for CHP and Ren^ables from Four Improvement Scenarios

Note l. Lincolnshire capacity is subject to developments in north Cambridgeshire and north-east Norfolk. Does not include capacity of Yorkshire Electricity network in north Lincolnshire.

70 4000

3500 ■ 2010 Target ■ Existing Capacity □ Plus TS Upgrades (1st stage) 3000 ■ Plus FL Upgrades ? □ Plus TS Upgrades (2nd stage) ^ 2500 ■ Plus Power Flow Upgrades & 5 6 2000 o ^4 ! S 1500 S o 1000 r Derbys Leics Lines Northants Notts East Midlands

Figure 5 Enhanced Network Capacity for CHP and Renewables from Four Improvement Scenarios

71 Table 21 also shows how the percentage of bulk supply groups which have no spare capacity is reduced by the four stages of improvements. Significant improvements are made by the first two stages in that this percentage is reduced from 52% unavailable to 10% unavailable.

In conclusion, the improvements made by relaxed stability requirements, fault level upgrades and possibly also some of the second stage of transient stability upgrades should enable the 2010 targets to be met. Further, subject to the distribution of generation developments, the 2010 targets could be comfortably exceeded.

On a county basis, the greatest restrictions appear to remain in Lincolnshire and Northamptonshire. This is due to a relatively low quantity of supergrid transformer capacity feeding Lincolnshire and the high level of 132kV connected generation at Corby, Peterborough and King’s Lynn (all CCGT power stations). These grid group constraints could, of course, be bypassed by any large scheme connecting to the transmission system at 400kV. Otherwise, additional supergrid transformer capacity, or closure of a CCGT station, would be required to provide additional capacity for CHP and renewables.

5.4 Recommended Actions to Improve Network Capacity

The following actions are recommended to improve the capability of the network to accept embedded generation, taking into account the 2010 targets for renewables and CHP:

(i) Apply relaxed transient stability requirements, allowing some generators to trip (before pole-slipping or other instability occurs) if they cannot remain connected for certain network faults. Suitable protection should be specified to ensure fast and positive tripping eg intertripping.

(ii) Specify pole-slip protection to provide positive back up protection on all synchronous generators. The estimated additional cost of this is £10k to £15k per generating unit, including engineering time to derive suitable settings.

(iii) Specify power system stabilisers on low inertia generators. The estimated additional cost of this is £20k per generating unit, including engineering time for computer simulations to derive suitable settings and on-site tuning and commissioning.

(iv) Initiate a programme of uprating of substation plant to increase fault rating, eg to 25kA at all high voltage levels from 6.6kV to 132kV. This will make connection capacity available at a large number of sites, thus improving flexibility in generator location, without compromising transient stability or quality of supply. The substations which should be targeted first are those where existing fault levels are close to ratings. The

72 estimated cost of upgrading the substations listed in Table 20 is £85m.

(v) Specify generator voltage control schemes to control generator reactive power output and also active power output as necessary, to ensure network voltages remain satisfactory. This will mainly apply to generation which is connected remotely from source substations which already provide automatic voltage control. The estimated cost of such a scheme is £20k per generating unit.

(vi) Uprate two 132kV double circuits between Corby, Irthlingborough and Kettering to allow additional unconstrained generation in the Corby area.

(vii) Replace two 132/33kV 45MVA bulk supply transformers at Annesley with modern units to provide a reverse power capability. This will enable additional unconstrained generation in the north Nottingham area.

(viii) As growth in embedded generation continues, it will be necessary to improve network fault clearance times to prevent degradation of power quality and security of supply caused by large quantities of rotating machines, many having low inertias.

The following areas are recommended for further research, development and implementation:

(ix) Fault current limiters.

(x) Generator series braking resistors.

(xi) Specification of a minimum value of generator inertia constant.

Other solutions discussed in this chapter are not necessarily appropriate as global network upgrades but may be implemented on a case-by-case basis when locations of generator developments are more accurately known.

73 6 CREATING A COMMON STUDY FORMAT

There are several issues which need to be considered in order to develop a consistent format for repeating these studies across other distribution networks in the UK.

6.1 Study Methodology for Large Networks

Distribution networks are very large networks (larger than transmission networks) in terms of the number of substations, circuits and connections to users. Development of a cost-effective method to assess the entire network therefore presents a significant problem. Two main alternatives are apparent:

• study small sample areas of the network in detail and then extrapolate these results to draw conclusions about the larger network

• perform analytical studies equally across the whole network but in less detail than would be possible for a limited number of sample areas

The former method has been used in these studies. It is not possible to extrapolate fault level restrictions across the network with confidence due to the different fault ratings of existing plant. Therefore, detailed knowledge of both fault levels and fault ratings at all substations in the network is necessary to perform an accurate assessment of constraints. Similarly, knowledge of local power flow problems, which again may not be apparent from extrapolation, should also be used in the assessment.

The disadvantage of the second method is that there is a minimum level of study detail to ensure meaningful results and therefore this will still require a large resource.

To some extent, the chosen methodology should be influenced by the relative importance attached to the following main objectives:

• identification of capacities at individual locations (to assist developers on an individual project basis) - requires detailed studies in all study areas

• identification of the capabilities of the whole region (to assist with regional planning and monitoring) - requires a methodology which considers the whole region with simplifying assumptions as necessary

• identification of the network improvements which are most likely to assist the implementation of the 2010 (and future) targets for CHP and renewables - generic solutions can be identified from a

74 few sample studies; however, targeted solutions require the wider network to be assessed

6.2 Measures of Regional Network Capacity

The measurement, presentation and interpretation of regional network capacity requires special consideration. A measure of regional network capacity can be obtained by determining the maximum generation capacity which can simultaneously connect and operate within the region. This approach optimises the capacity of the network by constraining the size and distribution of generation.

However, this capacity only considers constraints which exist in the network itself and does not take account of other constraints which occur in the development of generation projects. Thus, it assumes that generation can be flexibly located so that all favourable points on the network can be developed to their maximum potential. A few good sites may contribute to an apparently high total regional capacity, even though severe constraints may exist over wide areas of the network.

In practice, generation sites are not usually chosen based on network capabilities and it is therefore important for the network to be flexible so that as many connection sites as possible are available for connections at reasonable cost. A flexible network will allow the maximum network capacity to be achieved by a large number of generator combinations. The maximum capacity itself may still be limited, for example, by grid supply point capacity or transient stability considerations.

Key indicators of network flexibility which could be used are:

• the proportion of connection sites which are unreasonably constrained (to be suitably defined)

• the uniformity of the distribution of network capacity between similar substations

6.3 Computer Model Requirements

Power system analysis should be undertaken using computer models of the distribution networks. These models should be suitable for steady state load flow, short circuit analysis and transient stability analysis. The entire network from 400kV and 275kV grid supply point busbars down to llkV primary substation busbars should be included. Thus the entire l32kV and 33kV networks will be modelled.

All existing embedded generation should be included in the models. In grid groups which are shared between adjacent network operators, care should be taken to accurately represent the network and embedded generation in the neighbouring region.

75 If more emphasis is required on smaller distributed generation (eg PV, micro-CHP), then it will be necessary to analyse the network at llkV and 400V downstream of the primary substations. This network is vast and therefore it is likely that sample studies only will be viable.

6.4 Assumptions in Study Methodology

Assumptions can be divided into three categories: generator data; network conditions; planning criteria for acceptable generator and network performance. Variations in these assumptions will significantly influence the results. The key assumptions are listed below.

Generator Data

• Inertia constant: significantly affects transient stability performance of the generator and network.

• Reactive power requirements, eg is a reactive power export capability required? Is reactive power import allowed? These will significantly affect load flow, voltage profile and voltage step change results.

• Generator and transformer parameters: will affect fault level results.

Network Conditions

• Minimum load assumed in studies: this should include diversity and preferably be based on measured load at bulk supply points and primary substations. However, at distribution transformers (llkV to low voltage transformers), it is prudent for a minimum load of zero to be assumed.

• Network outages: these studies are based on the worst case outage of any single circuit in the distribution system.

• Maximum and minimum voltages at source substations (BSPs, primaries): these should be determined based on actual voltage control schemes. The values are critical in respect of voltage rise caused by generation connected to existing network feeders, remote from the source substations.

Planning Criteria

• Fault level margin: several companies include a tolerance, eg 5%, on calculated fault level results to take account of approximations in the network model. Variation of this tolerance will affect connection capacities.

76 • Transient stability requirements are often stated in terms of critical clearance times to avoid pole-slipping of synchronous machines or overspeeding of asynchronous machines. However, it is also necessary to consider the effect of rotating machines on network voltage recovery, to ensure that the effects of network faults are not exacerbated to the detriment of other network users. A criteria of voltage recovery to 0.9p.u. in 0.5s has therefore been applied in these studies.

77 7 REFERENCES

1 Viewpoints On Sustainable Energy In The East Midlands: A Study Of Current Energy Projects And Future Prospects - Final Report, March 2001, Land use Consultants and IT Power Ltd.

2 Engineering Recommendation G59/1, Recommendations For The Connection Of Private Generating Plant To The Public Electricity Suppliers ’ Distribution Systems, 1991, Electricity Association.

3 Engineering Recommendation G75, Recommendations For The Connection Of Embedded Generating Plant To Public Electricity Suppliers ’ Distribution Systems Above 20kV Or With Outputs Over 5MW, 1996, Electricity Association.

78 8 GLOSSARY

Asynchronous Machine An AC rotating machine (motor or generator) which operates at a lower or higher speed than synchronous speed; also referred to as induction machines, induction motors or induction generators

Bulk Supply Point (BSP) A substation in the distribution system delivering power from the 132kV network to the local 33kV or 11kV network. These substations have firm load capacities normally in the range 39MVA to 234MVA (based on cyclic capacity).

Converter A rectifier or inverter or combination thereof (eg an ac/dc/ac converter system)

Double Fed Induction An asynchronous generator in which both the Generator (DFIG) stator and rotor windings are connected to the network. One winding, typically the stator, is directly connected and is therefore energised at network frequency. The other winding is connected through an AC/DC/AC converter system which allows both the speed and reactive power of the machine to be controlled to a certain degree.

Grid Supply Point (GSP) A substation delivering power from the 400kV or 275kV transmission system to the 132kV distribution system. These substations have firm load capacities normally in the range 288MVA to 864MVA (based on cyclic capacity).

Inverter A device which converts direct current and voltage to alternating current and voltage.

Pole Slip Also referred to by the terms “loss of synchronism”, “unstable”, “instability”.

An event in which a synchronous machine fails to sustain continued operation in synchronism with the network. It may be caused by machine faults (such as loss of excitation) or network faults (such as severe voltage depressions as occur under short-circuit conditions). The effects of pole slipping may be very serious, equivalent to repeated short-circuits on the network, and may result in loss of supplies over large areas and mechanical damage to generating units (eg shafts, holding down bolts).

79 Power Factor The ratio of active power (watts) to apparent power (volt-amperes or VA), both measured at a specified point in a circuit. A lower power factor occurs when reactive power flows (vars) are increased.

Power System Stabiliser A device which acts to improve damping of (PSS) oscillations in rotating machines, normally by injecting a compensating signal into the machine excitation system. Currently applied to synchronous machines only.

Primary Substation A substation in the distribution system delivering power from the 33kV network to the 11kV network. These substations have firm load capacities normally in the range 8MVA to 40MVA (based on cyclic capacity).

Rectifier A device which converts alternating current and voltage to direct current and voltage.

Static Var Compensator A solid state device connected to transmission or (SVC) distribution systems to assist with voltage control by generating or absorbing reactive power.

Synchronous Machine An AC rotating machine (motor or generator) which, in the steady state, operates at synchronous speed as governed by the operating frequency of the system to which it is connected (ie synchronised).

80 APPENDIX A DIAGRAMS OF NETWORK CAPACITY

The following diagrams show the non-simultaneous connection capacities for the connection points studied in the Enderby/Leicester and Walpole/Boston groups. Separate diagrams are included for synchronous generators, asynchronous generators (Walpole/Boston group only) and converter connected generators and for 132kV, 33kV and 11kV connections. LEICESTER NORTH OMW

LEICESTER EAST OMW

ENDERBY WIGSTON OMW OMW

Figure A1 Enderby Group 132kV Substation Connection Capacities for Directly Connected Synchronous Generators (non-simultaneous)

A1 Redcross St OMW

Jupiter OMW

Highfields OMW

Braunstone OMW

Figure A2 Leicester Group 33kV Substation Connection Capacities for Directly Connected Synchronous Generators (non-simultaneous)

A2 Redcross St OMW

Jupiter OMW

Highfields OMW

Braunstone OMW

Figure A3 Leicester Group llkV Substation Connection Capacities for Directly Connected Synchronous Generators (non-simultaneous)

A3 LEICESTER NORTH 150MW

LEICESTER EAST 153MW

ENDERBY WIGSTON 450MW 140MW

Figure A4 Enderby Group 132kV Substation Connection Capacities for Converter Connected Generators (non-simultaneous)

A4 Redcross St 37MW

Jupiter 28MW

Highfields 23MW

Braunstone !3MW

Figure A5 Leicester Group 33kV Substation Connection Capacities for Converter Connected Generators (non-simultaneous)

A5 Redcross St 31MW

Jupiter 29MW

Highfields 25MW

Braunstone 2%MW

Figure A6 Leicester Group 11kV Substation Connection Capacities for Converter Connected Generators (non-simultaneous)

A6 STAMFORD 100MW

Figure A7 Walpole Group 132kV Substation Connection Capacities for Directly Connected Synchronous Generators (non-simultaneous)

A7 Tattershall Stickney 7MW 8MW

Wrangle 7MW Langrick 14MW Sleaford Rd 3MW Mount Bridge 2MW

BOSTON OMW

Kirton Donington 1OMW 5MW

Figure A8 Boston Group 33kV Substation Connection Capacities for Directly Connected Synchronous Generators (non-simultaneous)

68 Tattershall Stickney OMW OMW

Wrangle OMW Langrick OW Sleaford Rd OMW Mount Bridge OMW

Kirton Donington OMW OMW

Figure A9 Boston Group llkV Substation Connection Capacities for Directly Connected Synchronous Generators (non-simultaneous)

A9 STAMFORD 50MW

Figure A10 Walpole Group 132kV Substation Connection Capacities for Directly Connected Asynchronous Generators (non-simultaneous)

A10 Tattershall Stickney 8MW 9MW

Wrangle 13MW Langrick 12MW Sleaford Rd 4MW Mount Bridge 4MW

BOSTON 4MW

Kirton Donington 12MW 9MW

Figure All Boston Group 33kV Substation Connection Capacities for Directly Connected Asynchronous Generators (non-simultaneous)

611 Tattershall Stickney OMW OMW

Wrangle OMW Langrick OMW Sleaford Rd OMW Mount Bridge OMW

Kirton Donington OMW OMW

Figure A12 Boston Group 11kV Substation Connection Capacities for Directly Connected Asynchronous Generators (non-simultaneous)

A12 STAMFORD 100MW

Figure A13 Walpole Group 132kV Substation Connection Capacities for Converter Connected Generators (non-simultaneous)

A13 Tattershall Stickney 7MW 8MW

Wrangle 7MW Langrick 14MW Sleaford Rd 23MW Mount Bridge 18MW

BOSTON 85MW

Kirton Donington 10MW 5MW

Figure A14 Boston Group 33kV Substation Connection Capacities for Converter Connected Generators (non-simultaneous)

614 Tattershall Stickney 8MW 1.5MW

Wrangle 8MW Langrick 7MW Sleaford Rd 24MW Mount Bridge 17MW

Kirton Donington 8MW 8MW

Figure A15 Boston Group 11kV Substation Connection Capacities for Converter Connected Generators (non-simultaneous)

615