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NETWORK MANAGEMENT SYTEMS FOR ACTIVE DISTRIBUTION NETWORKS

A Feasibility Study

CONTRACT NUMBER:K/EL/00310/REP

URN NUMBER: 04/1361

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NETWORK MANAGEMENT SYSTEMS

FOR ACTIVE DISTRIBUTION NETWORKS - A FEASIBILITY STUDY

Report Number: K/EL/00310/REP URN 04/1361

Contractor SP POWER SYSTEMS LTD, SCOTTISHPOWER PLC

Prepared by

D A Roberts

The work described in this report was carried out under contract as part of

the DTI Technology Programme: New and Renewable Energy, which is

managed by Future Energy Solutions. The views and judgements expressed

in this report are those of the contractor and do not necessarily reflect those of the DTI or Future

Energy Solutions.

First Published 2004

© SP Power Systems Ltd, ScottishPower Plc

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EXECUTIVE SUMMARY

The following report discusses the technical feasibility of modifying an existing Distribution Network Operator (DNO) Supervisory Control and Data Acquisition (SCADA) system to one where some form of active management would be possible.

Introduction

Previous Government incentives have resulted in increasing amounts of embedded generation being connected to the UK distribution networks. There is now a drive to significantly accelerate this process to meet the governments 2010 targets for reducing CO2 omissions. Traditional methods of providing connections involve constructing new circuits, thereby increasing the network capacity. Whilst essential and unavoidable for many connections, such schemes can be time consuming and may have a significant cost in both monetary and environmental terms. In order to tackle these issues and to assist developers in the cost of connection, a number of generation connections have been accepted, which apply simple constraints when the system capacity is restricted. Network constraints, such as voltage limits and thermal overloads, typically only occur under particular outage conditions and load/generation patterns. This has resulted in a number of ‘hard-wired’ intertrip schemes being developed for individual generator connections, details of which can be found in ETR124*. Whilst this offers a solution for individual generators connected to a major substation busbar, it soon becomes unacceptably complex and increasingly difficult to modify when a number of generators are connected within the same network of that busbar, and multiple constraints need to be considered. This has been found to be the case in areas of some distribution networks, with the complexity of constraints themselves becoming the most significant barrier to the connection of further generation. There have been many debates in recent years on the subject of active networks, as applied to distribution systems and it is perceived that the ‘active network’ is an answer to achieving the levels of Distributed Generation (DG) proposed over the coming years. Indeed, recent statements by Ofgem are indicating that in the next Price Control, active management will be the preferred solution to the connection of DG. An active distribution system, based on the UK transmission models, where generation is dispatched to meet load and outage constraints is unlikely to be acceptable for the majority of (smaller) generators on technical and economic grounds. However, one alternative solution could be to utilise SCADA systems, across the network voltages 11kV to 132kV, in association with an appropriate ‘Active Control’ model. This could make it possible to monitor the network and issue signals to generator(s) to match their output to a range of network states, having the mutual benefit of allowing additional embedded generation to be

* Engineering Technical Recommendation 124, ‘Guidelines for Actively Managing Power Flows Associated with the Connection of a Single Distributed Generation Plant’.

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connected to distribution networks, at the same time as avoiding major network reinforcement.

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Objectives

This report is based around the UK Distribution Networks, that is those systems of 132kV and below in England & Wales, 33kV and below in Scotland. It has been written to: (i) Investigate the feasibility of developing a typical DNO SCADA system from a

passive data acquisition and control system to a dynamic active network management system.

(ii) Identify workable solutions and the benefits of such actively managed

networks in terms of increasing the capability of the networks to accept additional embedded generation.

(iii) Identify any changes to existing SCADA systems to facilitate the above proposals, and to produce a high-level specification for an active network management system.

The commercial implications, of which there are many, are not discussed and it is highlighted that the solutions identified do not form any part of the SP Power Systems Ltd existing system design policy for the SP Manweb, SP Distribution or SP Transmission networks. Summary of Work

The layout of this report reflects the process in which data was collected and analysed to determine the technical feasibility of using an existing network management / SCADA system for active management. The key aspects are: • The existing design and control philosophy used for connecting DG, and the

areas where restrictions are having an impact on future connections. • The existing distribution SCADA systems, taking some generic models from the

similarities of a number of UK DNOs. Any limitations in architecture and communication channel / Remote Telemetry Unit (RTU) capabilities have been highlighted.

• The identification of common themes that need to be considered to permit the use of SCADA for active network management.

• A discussion defining passive and active management as used in this report. The identification of active management solutions that may be suitable for application through the SCADA systems.

• The development of technically possible SCADA solutions for both load constraint management and network voltage control.

It should be noted that the solutions presented in this report should not be seen as prescriptive and exhaustive in that there could be circumstances where a DNO is unable to accept the solutions proposed here. It is paramount to bear in mind that it is the local DNO that holds the overriding design authority for their own network and any proposals would need to be approved by them.

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Report Summary

The potential advantages of using the DNOs SCADA system for the purposes of possible active network management principally relate to the utilisation of existing communications and hardware infrastructure. Further advantages include: • SCADA is distributed throughout the electricity network (from 33/11kV

transformers and upwards). • SCADA logic is software based, therefore it can be made adaptable. • SCADA has been used in the electricity industry for over 30 years to operate

circuit breakers, or signal to control room, its principles are widely accepted. This report however concludes that: 1. There are fundamental limitations to the speed of operation, reliability and

resilience of existing SCADA systems that would limit its application where the consequence of failure is significant.

2. The complexity of logic programming and lifetime management of logic configurations could become a major risk and carry significant cost overheads to the DNO unless simple, modular schemes were achievable.

3. Resilient communications is a key requirement of any SCADA or other active management solution. This is currently not widely available in existing Distribution networks.

4. There will be safety and operational implications that will require an associated culture change to occur in the Electricity Industry as active management solutions become more common.

1. Fundamental Limitations of Existing SCADA 1.1 Speed of Operation and Operational Capability Although SCADA has successfully been used to implement a number of network automation schemes for the purposes of supply restoration, it is not so straightforward to apply this technology to generator active management where the consequence of non-operation could be significant to system security or safety. For many network constraints, especially load (or fault level) management, the time taken from identification to the issuing of actioning signals can be crucial. This is due to the settings of line protection, as it is imperative that the control signal has the chance to operate prior to a protection operation, resulting in the opening of circuit breakers. The SCADA systems used by UK DNOs are a mixture of 2nd and 3rd generation systems (early 1980s / 1990s technologies respectively). These were originally designed to make the most efficient use of the low bandwidth communication channels available at the time. They do not give true visibility of the network, but rather a snapshot, which is updated on a staggered basis between sites, at a frequency of around 5-15 seconds. Under non-quiescent conditions (such as a weather storm, causing substantial and widespread plant movements) times can increase significantly.

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1.2 Reliability and Resilience Existing SCADA systems are not designed or tested with the same rigour as is carried out for protection equipment, a factor based on the criticality of the asset and the associated risk of failure. The use of SCADA for purposes other than those that it was originally designed for present issues in terms of its inherent robustness and lack of fail-safe features in its design. There are techniques that can be used to determine the reliability of a system based on the failure rates of each component. However due to the number of variables involved in a SCADA active management solution, unless considered in depth, the overall reliability figure is likely to be lower than that of any traditional solution. 2 Complexity and Lifetime Management 2.1 Bespoke Schemes for a Bespoke Network Although each DNO has design standards, the networks have been developed to suit the requirements of the local load. This has led to inherently unique network topologies that, coupled with the numerous variables in generation connection, will generally require unique active management solutions. It is noted that a SCADA solution would best suit modular systems that are simple and standardised. 2.2 Lifetime Costs The electricity network is not static. It varies by the second, hourly, daily, seasonally and annually, through outages, load changes or other network developments. To this end, it is likely that the specifics of any associated active management solution will also have to change on a similarly frequent basis. Whilst it is possible that it may be easier to deliver these changes through a SCADA (or software) solution, the analysis that gives rise to the changes may be extremely time-consuming and costly. 3 Communications 3.1 Penetration of High-Speed Communications Although high-speed communications are becoming more and more widespread in the public domain, eg advances in broadband internet service, use is still largely restricted to populated urban areas. It is noted that communications in rural areas are sparse, and although the telecommunications companies can extend their networks to these areas, the associated installation costs can be extremely high. To improve the speed of the existing SCADA communications network it may be necessary to install point-to-point communications. This would be a change from the existing pyramidal type structure, which rely on line sharing and multi-dropped RTUs. 3.2 Reliability, Diversity and Resilience Anecdotal evidence is indicated that the reliability of 3rd party owned communications channels is worsening, especially in rural areas. For the true active network, it is likely that reliable, secure communications will be an essential factor.

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The cost to obtain a truly secure and diverse channel, especially in rural areas can be significant. 4 Safety and Operational Implications 4.1 Staff Safety The use of active network management through SCADA or any other means will require a significant change in working practice and culture. Although staff are given a thorough training on the existing hazards on the electricity network (electrocution, induced voltages, etc), they will have to become familiar with any associated active management systems that may put themselves or others at risk throughout the cause of their work. 4.2 Operational Implications Further training will be necessary to give a thorough understanding of any active management solutions applied on a network to all operational staff (from the DNOs control room to field operatives). This is essential to ensure that when switching activities are undertaken the relevant persons are fully aware of how to disable / enable systems and the implications of not doing so. It is noted that a SCADA active management solution would necessitate a basic understanding of the SCADA system, currently not held by many operational persons.

SCADA Active Management Possibilities

Although these limitations apply particularly to load management where external communications are necessary, there are technical development possibilities for cases where the speed of operation, complexity and communications issues are not significant. Examples where solutions could be developed in relatively short timescales include: • The dynamic use of the two / four season ratings of circuits.

Most circuits have seasonal ratings, which take advantage of the cooling effects in ambient temperatures. Typically, alarm settings in the DNOs control room are set to the more conservative summer rating. A conceptually simple advancement would be to switch these over throughout the year.

• The thermal modelling of lines. To further improve the line ratings, a number of tools are becoming available that can sit on the network, taking into consideration the heating effects of current down a line, solar gain, etc, and accounting for the cooling effects of the ambient temperature and wind across the line. These factors are run through an algorithm to develop a true circuit rating, which can be fed back to automatically update alarm limits or other constraint management systems. Perhaps the biggest challenge with this would be in gathering the data to accurately assess and calculate the ratings of cables/lines at all voltages (current data is only available for 132kV circuits).

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• Local embedded SCADA constraint management

It is possible with some of the more modern SCADA Remote Telemetry Units (RTUs) to build in simple logical sequences that can take local inputs (ie current, circuit breaker status, etc) and issue signals to a local device (eg a generators control system connected at that substation).

• Network voltage optimisation through the use of Optimum Power Flow (OPF) software and the remote control of transformer tap-changer set point settings.

To further optimise network voltages to account for variable generation / load, a suitably designed OPF software tool can be co-located with the SCADA Host and used to feed into transformer automatic voltage control units, altering setpoints within a predetermined range.

Although the SCADA developments outlined above may be technically achievable, there may be other solutions, which may be more economically or technically suitable. Furthermore, the financial viability of the solutions discussed in this report has not been considered. As the UK DNOs operate in a regulated environment, there would need to be agreement with the Regulator (Ofgem) about funding and the recovery of costs.

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Further Work

This report has identified a range of high level technical possibilities for the application of active management in SCADA. Prior to implementation, a thorough assessment of each solution against the relevant technical, commercial and Regulatory factors must be undertaken. As dialogue needs to be encouraged at a National level with all Stakeholders to discuss the feasibility of the enclosed solutions, their relevance and application, these recommendations may be best taken forward by Distributed Generation Co-ordinating Group, Technical Steering Group: Work Stream 5 “Long-Term Network Concepts and Options” (DGCG, TSG – WS5). Recommendations

The principle recommendations that could facilitate active management through SCADA are to: • Develop standard modular generation connections (in terms of SCADA

equipment and communications infrastructure) • Overcome the inherent SCADA limitations regarding speed of operation and

resilience through robust industry-wide, approved designs. • Develop a suitable communications infrastructure between the necessary nodes

on the distribution network. • Overcome the risks to the DNO through the consequence of SCADA or

communications failure through thorough design. • Simplify constraint management and associated active management systems (to

overcome the complexity issues). • Investigate the safety and operational implications of using SCADA for active

management – dialogue should be encouraged at a national level including the DNOs, HSE, DTI and other significant stakeholders.

Following such developments, it may be possible for the industry to develop a ruleset for SCADA active management similar to those outlined in ETR124 for single generator connections. Whilst not directly tackled in this report, it is essential that the commercial risks are considered in conjunction with any technical aspects, including:

• The cost effectiveness of the SCADA solution against alternative products. • The reliability and associated risks of failure, both financial and though

Licence penalties. • An appropriate Financial Framework / incentives encouraging DNOs to invest.

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CONTENTS

1 EXISTING NETWORKS ____________________________________________________ 1

1.1 Design Philosophy _____________________________________________________________ 1

1.2 Generation Connection Philosophy______________________________________________ 1

1.3 Issues _________________________________________________________________________ 2

1.4 Existing Solutions______________________________________________________________ 2 1.4.1 Loadflow_________________________________________________________________________ 2 1.4.2 Voltage __________________________________________________________________________ 2 1.4.3 Fault Levels ______________________________________________________________________ 3 1.4.4 Existing Load Management Systems _______________________________________________ 3 1.4.5 Existing Operational Methodology and Philosophy __________________________________ 4

2 EXISTING SCADA SYSTEMS_______________________________________________ 5

2.1 Architecture ___________________________________________________________________ 5

2.2 Communications_______________________________________________________________ 6

2.3 RTUs__________________________________________________________________________ 7

3 CENTRALISED VS DISTRIBUTED CONTROL _________________________________ 8

3.1 Overview______________________________________________________________________ 8

3.2 Centralised SCADA Systems ____________________________________________________ 8

3.3 Distributed SCADA Systems ____________________________________________________ 9

4 ACTIVE MANAGEMENT POSSIBILITIES ____________________________________ 10

4.1 Active Vs Passive Control – Report Definitions __________________________________ 10 4.1.1 Overview _______________________________________________________________________ 10 4.1.2 Passive Control __________________________________________________________________ 11 4.1.3 Active Control ___________________________________________________________________ 11

4.2 Suitable Active Management Solutions for Implementation in SCADA ____________ 13 4.2.1 Overview _______________________________________________________________________ 13 4.2.2 Principles _______________________________________________________________________ 13 4.2.3 Suitable Solutions _______________________________________________________________ 14

5 TECHNICALLY POSSIBLE SCADA SOLUTIONS BUILDING ON THE ACTIVE UNIT, CELL AND NETWORK CONCEPTS _____________________________________________ 15

5.1 Changes to SCADA architectures_______________________________________________ 15 5.1.1 Overview _______________________________________________________________________ 15 5.1.2 SCADA Active Unit ______________________________________________________________ 15 5.1.3 SCADA Active Cell _______________________________________________________________ 17 5.1.4 SCADA Active Network___________________________________________________________ 19 5.1.5 Discussion ______________________________________________________________________ 19

6 TECHNICAL CHALLENGES TO THE IMPLEMENTATION OF SCADA ACTIVE MANAGEMENT ______________________________________________________________ 20

6.1 Bespoke Generation Connection Schemes ______________________________________ 20 6.1.1 Overview _______________________________________________________________________ 20 6.1.2 Network Design and Constraints __________________________________________________ 20

6.2 SCADA Limitations____________________________________________________________ 21 6.2.1 Operating Speed ________________________________________________________________ 21

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6.2.2 Event Driven Data and Timing ____________________________________________________ 21 6.2.3 Change of Operation _____________________________________________________________ 22 6.2.4 Asset Functionality ______________________________________________________________ 22

6.3 Communications______________________________________________________________ 23 6.3.1 Limitations ______________________________________________________________________ 23 6.3.2 Reliability _______________________________________________________________________ 23 6.3.3 Use of IP ________________________________________________________________________ 24 6.3.4 Communications Failure _________________________________________________________ 24

6.4 Consequence of Non-Operation ________________________________________________ 24 6.4.1 Levels of Overload _______________________________________________________________ 24 6.4.2 Timing Criticality ________________________________________________________________ 24 6.4.3 Network Risk and Change Management ___________________________________________ 26

6.5 Complexity ___________________________________________________________________ 27 6.5.1 Database / Logic Management ____________________________________________________ 27 6.5.2 Software Logic Testing___________________________________________________________ 27 6.5.3 Future Uses _____________________________________________________________________ 27 6.5.4 Ownership ______________________________________________________________________ 28 6.5.5 Operational Complexity __________________________________________________________ 28

7 CONCLUSIONS __________________________________________________________ 30

8 GLOSSARY ______________________________________________________________ 34

9 ACKNOWLEDGEMENTS __________________________________________________ 38

10 REFERENCES ____________________________________________________________ 40

APPENDIX A _________________ – EXISTING DNO DESIGN & CONTROL PHILOSOPHY A1

A.1 Network Design – General System Overview ___________________________________ A1

A.2 DNOs Obligations____________________________________________________________ A2 A.2.1 Fault Protection__________________________________________________________________A2 A.2.2 Network Performance ____________________________________________________________A3 A.2.3 Loadflow________________________________________________________________________A3 A.2.4 Voltage profiles__________________________________________________________________A3 A.2.5 Fault Level ______________________________________________________________________A3 A.2.6 Frequency_______________________________________________________________________A3

A.3 Changes in Network Design for the Connection of Generation ___________________ A5 A.3.1 Overview _______________________________________________________________________A5 A.3.2 Loadflow Solutions ______________________________________________________________A5 A.3.3 Voltage Profile Solutions _________________________________________________________A7 A.3.4 Fault Level Solutions____________________________________________________________A11

A.4 Electricity Network Control __________________________________________________ A11 A.4.1 Overview ______________________________________________________________________A11 A.4.2 Network Control Practices for Embedded Generation Connections __________________A11 A.4.3 Control Room Experience of Existing Systems ____________________________________A12

APPENDIX B ______________________________________ – EXISTING SCADA SYSTEMS B1

B.1 Overview_____________________________________________________________________B1

B.2 Generic SCADA System Architecture ___________________________________________B3 B.2.1 Overview _______________________________________________________________________ B3 B.2.2 Age profile, intelligence, capabilities and functionality of the RTUs___________________ B5 B.2.3 Communication Channels ________________________________________________________ B6

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B.3 Protecting and Controlling the Network_______________________________________ B10

APPENDIX C _– COMMON THEMES FOR THE IMPLEMENTATION OF SCADA ACTIVE MANAGEMENT ______________________________________________________________C1

C.1 Centralised Vs Distributed Logical Switching Schemes___________________________C1 C.1.1 Overview _______________________________________________________________________ C1 C.1.2 Methods ________________________________________________________________________ C1 C.1.3 Central SCADA Implementation___________________________________________________ C2 C.1.4 Distributed SCADA System _______________________________________________________ C3

C.2 Generic Advancements________________________________________________________C4 C.2.1 SCADA Availability on Network (Switchgear) ______________________________________ C4 C.2.2 Communication Channels ________________________________________________________ C4 C.2.3 Remote Terminal Units___________________________________________________________ C7 C.2.4 Future Proofing_________________________________________________________________C10

APPENDIX D– PROPOSED SOLUTIONS FOR SCADA ACTIVE MANAGEMENT_____D1

D.1 Future SCADA Applications to Accommodate Generation _______________________ D1

D.2 Potential Loadflow Solutions _________________________________________________ D1 D.2.1 Overview _______________________________________________________________________D1 D.2.2 Improved Network Thermal Modelling ____________________________________________D2 D.2.3 Constraint Management__________________________________________________________D6 D.2.4 Load / Generation Forecasting ___________________________________________________D15

D.3 Potential Voltage Profile Solutions ___________________________________________ D16 D.3.1 Background ____________________________________________________________________D16 D.3.2 Existing Load-Shedding Systems ________________________________________________D17 D.3.3 Remote Change of Transformer AVC Setpoint_____________________________________D18 D.3.4 Automatic Network / Generator Voltage Control ___________________________________D19

D.4 Potential Fault Level Solutions _______________________________________________ D20 D.4.1 Overview ______________________________________________________________________D20 D.4.2 Network Reconfiguration ________________________________________________________D21

D.5 Holistic Solutions – Network Optimisation Software ___________________________ D23

APPENDIX E – TECHNICALLY POSSIBLE SCADA ACTIVE UNIT, CELL AND NETWORK PROPOSALS ___________________________________________________________________ E1

E.1 SCADA ‘Active Unit’ Solutions (Local Logic) ____________________________________E1 E.1.1 Introduction _____________________________________________________________________ E1 E.1.2 Dedicated Hard-Wired Logic ______________________________________________________ E1 E.1.3 Local RTU_______________________________________________________________________ E2

E.2 SCADA Active Cell Solutions___________________________________________________E4 E.2.1 Introduction _____________________________________________________________________ E4 E.2.2 Signals from Local CTs___________________________________________________________ E5 E.2.3 Dedicated GCSS RTUs ___________________________________________________________ E5 E.2.4 Central and Substation SCADA System Communications and Real-Time Databases ___ E6 E.2.5 Centrally Based Active Cell Solutions_____________________________________________ E11

E.3 SCADA Active Network Architecture___________________________________________E12 E.3.1 Overview ______________________________________________________________________ E12 E.3.2 SCADA Voltage Control Solutions________________________________________________ E14

E.4 SCADA Solution Discussion __________________________________________________E18

APPENDIX F – OVERVIEW OF DNOS SCADA ARCHITECTURE ____________________ F1

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F.1 SP Manweb __________________________________________________________________ F1 F.1.1 Overview _______________________________________________________________________ F1 F.1.2 Architecture _____________________________________________________________________ F2 F.1.3 SCADA Components and Capabilities _____________________________________________ F2

F.2 SP Distribution (ScottishPower) ________________________________________________ F4 F.2.1 Overview _______________________________________________________________________ F4 F.2.2 Architecture _____________________________________________________________________ F4 F.2.3 SCADA Components and Capabilities _____________________________________________ F5

F.3 Aquila Networks (Midlands Electricity)__________________________________________ F6 F.3.1 Overview _______________________________________________________________________ F6 F.3.2 Architecture _____________________________________________________________________ F6 F.3.3 SCADA Components and Capabilities _____________________________________________ F7 F.3.4 Communication Network details __________________________________________________ F7

F.4 Northern Electric Distribution (Northern Electric) ________________________________ F8 F.4.1 RTU Types ______________________________________________________________________ F8

F.5 United Utilities Electricity (NORWEB) ___________________________________________ F8 F.5.1 RTU Types ______________________________________________________________________ F8

F.6 East Midlands Electricity_______________________________________________________ F9 F.6.1 RTU Types ______________________________________________________________________ F9

F.7 Other DNOs _________________________________________________________________F10 F.7.1 SSE Power Distribution (Scottish Hydro Electric) __________________________________ F10 F.7.2 EDF Energy Networks (Eastern Electricity) ________________________________________ F10 F.7.3 YE Distribution (Yorkshire Electricity)_____________________________________________ F10 F.7.4 EDF Energy Networks (SEEBOARD) ______________________________________________ F10 F.7.5 SSE Power Distribution (Southern Electric) _______________________________________ F10 F.7.6 EDF Energy Networks (London Electricity) ________________________________________ F10 F.7.7 Western Power Distribution (South Western Electricity) ____________________________ F10 F.7.8 Western Power Distribution (SWALEC) ___________________________________________ F10

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1 EXISTING NETWORKS

1.1 Design Philosophy

The UK electricity networks have changed dramatically since electrification in the early 1900s, however, historically, DNOs have always concentrated on load customers. This has resulted in networks principally dedicated to uni-directional and passive load flows. With the potential increase of generation connections over the coming years, networks will have to be designed or modified to cope. This is an inherent shift in design principles, allowing generator connections to be facilitated more fluidly, ie the analogy of ‘Plug-and-Play’ in Personal Computers. To do this, generation will have to be considered as an integral part to the DNO’s system, an inherent culture change in the design and operation of the distribution network. It is noted that it is more technically challenging design a network that will fulfil the requirements of variable load and variable generation patterns.

1.2 Generation Connection Philosophy

The local network topology is an essential consideration in the connection of any generator. DG developers have to site their generators in the best position to their source, ie windfarms in the areas of high average windspeed, but for the DNO, these are the traditional low load areas, with few customers and associated ‘weak’ electrical networks. In order to facilitate these connections, meet Legal & Licence compliance and provide a least cost option, the DNO often has to modify their standard designs, stretching their network both in terms of plant ratings and network complexity. Clearly, the preferred method of connecting generation to the distribution network has to be a solution that is cost effective and meeting all other requirements of all stakeholders (ie the DNO, its customers, the generator, Ofgem and the UK as a whole). The volume of generation connected at distribution voltages is currently manageable through conventional mechanisms, albeit reaching saturation in some heavily developed areas. The unpredictability of future generation connections in terms of both volume and location can make it difficult to target network investment specifically towards active management, as it is the market that determines when / where a connection will be commercially viable (of which the DNO has no control). This is reflected through generation connection enquires. The NFFO proposals of the mid 1990s, encouraged many smaller generators connected to the lower distribution voltages, however more recent enquiries suggest either fewer but larger connections (eg to the 132kV or higher networks), or the replanting of existing wind turbines for more modern higher output machines.

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1.3 Issues

The are a number of the DNOs Legal and Licence Obligations that can be affected through the connection of DG. This report focuses on the technical feasibility of some of these, namely: • Loadflow: The thermal rating of lines and cables. There are two main factors that

will have an affect on overload: the actual ratings the circuits themselves and the amount of power transmitted down the line.

• Voltage profiles: The impact on Statutory Regulations and effects on DNOs other customers.

• Fault Level: Ensuring the DNOs design fault level ratings are not exceeded, which may result in increased stress to equipment.

1.4 Existing Solutions

The existing methodology is to design a network capable of facilitating 100% connected generation export for a fully intact network – consequently, constraints should currently only apply when the network is configured abnormally (either through planned or unplanned circuit outages). However, as the number of generation connections increases and network capacity becomes restricted, more and more constraints may start to apply under system ‘normal’. Due to restrictions in the ratings of lines and cables or voltage problems under circuit outage conditions, a number of systems have been installed to existing generation connections giving the DNO the ability to trip the generator. This practice, using a series of hardwired ‘operational’ intertripping schemes, charged to the connecting generator is still standard design policy, albeit dramatically increasing the complexity of a network.

1.4.1 Loadflow Generator constraining for limiting loadflow can take many forms, some examples include: • All off intertrip – A signal is sent to open the connecting circuit breaker of all

generators connected to a feeder, or network group (in the case of an interconnected network).

• 33% / 66% reduction signals – Signals are sent to a generator to cut their export first by 1/3, then, if necessary, by 2/3. If the generator fails to do so in the allotted time, a trip signal is sent to open the DNOs connecting circuit breaker.

It is noted that on networks with limited generation connected, the constraints are generally subjected to just a single generator and there is no interaction between sites. Guidance to DNOs on such schemes is provided in ETR 124 [13].

1.4.2 Voltage The main widespread active control on the existing UK distribution network is the voltage profiling of the 132kV, 33kV and 11kV networks using Automatic Voltage

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Control (AVC) schemes in association with transformer tap-changers. The only occasion where this is not practice, is in some heavily urbanised areas where a high network density ensures tighter control of the network voltages. Other solutions currently used, although limited, include: • In Line Voltage Regulators • Line or substation Capacitors

1.4.3 Fault Levels There are currently no systems in place to automatically control the network to ensure that design fault levels are not exceeded. The responsibility rests with the DNOs System Design to design a suitably robust network so that equipment operates within its limits.

1.4.4 Existing Load Management Systems As mentioned above, existing loadflow constraints generally apply only when the system is configured abnormally (eg Single Circuit Outage), as there is often sufficient firm capacity designed for the generation connection. However, it is noted that in order to facilitate future generation connections, it may be necessary to investigate constraint under system normal. Whilst hard-wired tripping can be built to be fail-safe, fast operating and is reasonably inexpensive it does have its limitations. The biggest limitation, is for when there are a number of generators employing hard-wired logic and another generator wishes to connect to that network (or other factors result in network reconfiguration). Here, all of the systems may have to be changed or even replaced to achieve the necessary grading to ensure each generator is constrained in the correct manner. Whilst this may be manageable under the present climate with few generation connections, it can be costly. It is of note that the ramp rates of modern wind turbine generators are of the order 25kW/sec per turbine, however many of the hard-wired constraint management systems do not exploit this as the generator is often only given seconds to react to a signal, prior to a trip. Once the trip is initiated, operation is quick (of the order 200ms, using high-speed protection equipment). This can introduce a race condition between schemes, which in turn may result in a number of generators (at remote locations) being disconnected for only a slight overload. From a network control point of view, this can be as problematic, leading to voltage step changes outside Statutory limits for the period until the associated transformer tap-changers can operate (of the order 30s – 1min). It is noted that if generators could be constrained or enabled in ‘blocks’, and even staggered between one site and another, this would give the network time to react to the changes.

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1.4.5 Existing Operational Methodology and Philosophy As generation constraint management systems have been introduced, there has been limited ad-hoc training given to field and control room operatives alike. It is noted that whilst the solutions are reasonably simple and locally based, the management in terms of switching in/out, providing local isolation, commissioning, testing, etc is relatively straightforward. As the systems develop and start to interfere or interact with other adjacent active management solutions / networks, significant operational issues will arise. It will be essential that full knowledge of the active management solutions (however implemented) will need to be available to all operational staff. This may require significant training or systems to be put in place to give site based operatives the visibility needed 24 hours a day, 7 days a week.

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2 EXISTING SCADA SYSTEMS Supervisory Control and Data Acquisition (SCADA), refers to the communications and control system from a remote substation to the control room. There are three primary SCADA signalling types: • Analogue Data – Currents and Voltages measured from on-site transducers

(CTs/VTs). • Digital Data – Eg Circuit breaker / isolator position indications, protection

operation flags, etc. • Control – The facility to remotely open or close a circuit breaker or motor driven

isolator.

2.1 Architecture

The SCADA currently in place throughout the UK is a mixture of 2nd or 3rd generation systems. • 1st Generation (1960s technology): An amalgamation of old telephone technology

and discrete components to take ‘change-of-state’ alarms back to a local, manned substation.

• 2nd Generation (1970s technology, deployed widely throughout 1980s): Remote Telemetry Units (RTUs) are polled every x seconds, for a set number, y, milliseconds, with information extracted to provide the control room with a snapshot of the network at that instant.

• 3rd Generation (1980s technology, deployed widely throughout 1990s): These operate on the basis of ‘exception’ reporting. In this system slave RTUs are polled in the same manner as the 2nd generation systems, but asked whether they have anything new to report (this is more bandwidth efficient than 2nd generation under quiescent conditions).

A typical UK DNO SCADA architecture consists of: SCADA Host • Centralised high availability SCADA systems to control networks 6.6kV+. • High availability central servers (dual) on high bandwidth LANs, generally located

at geographically diverse sites. • Operational functionality (for 132kV to 6.6kV) that may consist of the following:

• SCADA – data acquisition, data processing and remote control • Alarm processing • Historical data • Sequence / rota disconnection / emergency demand control switching • Graphical HCI with schematic drawing • Switching schedules and safety documents • Load planning tools

On Network • At the higher voltage sites (eg 132/33kV), data concentrators may be employed to

collect information from a number of downstream RTUs.

- 6 -

• The communications tend to be more secure the higher the voltage, with key sites utilising two or more diverse routes.

• At the very top-level, triangulation may be utilised to account for faults on the communications system.

Main ControlRoom

Host I

Standby ControlRoom

High Speed IP Link

Host II

RTU

RTU

RTU

RTU

RTU

132/33kV s/stn

Modem RTU

132/33kV s/stn

Mod

em

RTU

132/33kV s/stn

Modem RTU

132/33kV s/stn

Mod

em

RTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU RTU

RTU

RTURTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU RTU

RTU

RTURTU

RTU RTU

RTU

RTU

RTU

RTU

RTU

RTU RTU

RTU

RTURTU

RTU

RTU

RTU

RTU

PW Lines PSTN Lines

Lower bandwidth, separate channels

Point to PointCommunications

To other GridSubstations

High availability,high bandwidth

channels

TriangulatedCommunications

PW Lines

Figure 1: Generic SCADA Overview from RTU to Control Room

It is noted that the SCADA systems are more extensive and robust at the higher voltages such as 132kV. There is generally much less SCADA capability on the distributed 11kV networks below Primary (33/11kV) substations.

2.2 Communications

UK DNOs operate their networks over a range of diverse geographical topologies from built-up urban to dispersed rural networks. Their SCADA infrastructure was developed accordingly, utilising the most available and cost effective communications channels in the area. This has led to varied communication channel infrastructures with each DNO using a different system to the next. The communications used (generally) have the following characteristics:

• Analogue circuits • Relatively slow: 600, 1200, 2400 baud • Duplicate routes into key sites at higher voltages (ie 132kV) • ‘Multi-dropped’ with up to 10/15 RTUs per line • A combination of communications circuits (eg private pilot cables, rented

copper circuits, rented fibre circuits, mobile phone technology and radio)

- 7 -

Communications Channels Reliability The existing communications infrastructure principally consists of copper cable installed over a wide time period, from the start of the telecommunications development, to present day. As with any system exposed to the elements, deterioration occurs over time resulting in system faults. As the DNOs require communication channels over a wide geographical area, the length of which coupled with the extremely high reliability requirements often leads to difficulties in attaining a truly secure service. Many copper circuits have varying levels of performance with regards to their behaviour during disturbances caused by overvoltages. It has been shown that the fault tolerance is best achieved using optical fibres, which are not widely available, particularly in rural areas. It has been highlighted on many occasions that securing effective, duplicate, diverse and reliable rented channels in, again, rural areas (where many of the current renewable generators are located) are both difficult and expensive

2.3 RTUs

The functionality of RTUs used by different DNOs varies greatly, however, the following is fairly common:

• Time tagging of switch changes and alarms with up to one millisecond accuracy (typically 10ms).

• Measurements of analogues with alarm limit checking and percentage change.

• Digital outputs with configurable pulse duration. • Intelligent relay connectivity. • Programmable. Whilst not an extensively used system, logical sequences can

be programmed into some, more modern, RTUs and executed on specified plant triggers.

- 8 -

3 CENTRALISED VS DISTRIBUTED CONTROL

3.1 Overview

As network control becomes more dependent on SCADA systems, the amount and type of data being transmitted from remote substation back to a centralised control room may have to be reviewed. Increasing the length of any communications channel will result in an increase in the risk of faults along that circuit. To this end, many of the active management solutions may be best located at strategic substations, rather than back in the DNOs control room.

3.2 Centralised SCADA Systems

There are certain functions that must be controlled centrally (eg rota load shedding sequences, global voltage reduction, etc). The key problem associated with this method of implementation is the provision of a suitable reliable communications infrastructure between the central SCADA site and the substations where it will be necessary to control the network. If these are main Primary (33/11kV) substations there is likely to be an RTU in place. If they are small Secondary (11kV/LV) substations no RTU will be in place and more importantly there will be no communications infrastructure in place to the substation. Response times between SCADA / system and RTU will therefore be slow (several seconds) for detection of switch changes. Pros • The centralised SCADA system with sequence capability may already in place. • The SCADA system will contain the network diagram and asset database, which

could provide the basis of intelligence to be built into the sequences. • Maintenance facilities for hardware, software and database are already in place. • Configuration control of software and data (sequences) is centrally managed. Cons • Some of the older DNO SCADA systems may not have a sequence control

capability or the computing capability to undertake this task, so new SCADA systems may be required.

• A suitably reliable and available communications infrastructure may be necessary, with suitable fallback systems for communications failure.

• Response times for the detection of switch changes may be too slow, which may prevent sequences being carried out in the required time. However, this is application dependent.

• Testing may be difficult because of the physical distances involved. • Complex central bespoke logic, which may require extensive testing and change

management systems. • Risk of single point of failure (ie it all falls over together!). • Response times will be limited by the communications network.

- 9 -

3.3 Distributed SCADA Systems

A distributed SCADA solution would comprise, with small SCADA systems being located in a substation local to the distributed generation or elsewhere on the network. It may be necessary to install a communications infrastructure, the design of these systems would have to reflect the required mean time before failure / availability criteria. It would be advantageous if a single facility existed for the management and generation of the sequence schemes, which could be distributed manually or via a dedicated support / monitoring workstation. In some cases this could be the central SCADA system. Some means of remote health monitoring of the system would be necessary. Pros • If simple, modular and repeatable logic can be applied then the capital

expenditure may be cost effective. • The communications infrastructure could be provided by a low cost exception

reporting radio system (although this is application dependent, it would generally be unsuitable for continuous monitoring or Primary-to-Primary substations – given the distance).

• Subject to application, the response times / performance requirements could be met.

• May be possible to create simple modular approach to logic. Cons • It may be incompatible with the central SCADA system. • Additional maintenance facilities and skills (DNO and third party) may be

necessary for hardware and software. • Multiple distributed SCADA systems could be difficult to arrange unless some

management tool was put in place together with a communication path. • It may require field visits for logic modification. • Additional field staff may be required. • Solution may be less ‘asset effective’ than, say a hard-wired intertripping

scheme, for thermal overloads – this would be dependent on the complexity and repeatability of a SCADA solution.

• Response time would be limited by communications network. It is application dependant as to which technology would be the most suitable and cost effective as these are currently in their infancy and there are no simple rules or repeatable logic that can be applied globally.

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4 ACTIVE MANAGEMENT POSSIBILITIES

4.1 Active Vs Passive Control – Report Definitions

4.1.1 Overview Consider the example of Figure 2, a generation developer wishes to connect a 40MVA generator into the DNOs network. To accommodate this, a passive method may be the connection into the 132kV network, giving two lines, each with a rating well in excess of the generator’s needs, and giving full contingency under outage conditions. The solution is however, expensive. In contrast, an active solution could be the connection to the 33kV network. Whilst cheaper in implementation there is be a requirement to install control equipment to constrain the generator under (n-1) outage conditions, limiting its output to a level below the rating of a single line (in this case 20MVA).

Passive ManagementKey: Build Infrastructure to suit Customers

Timescales: Long-term

400/132kVTransformer

132/33kVTransformer

40MVAWindfarm

10km

5km

132kV Network

33kV Network

2 x 80MVACapacity Line

Full Generation Capacity MetNo Constraints NecessaryCost of Implementation = £4-6M

Active ManagementKey: Control Customers to suit Infrastructure

Timescales: Short-term

132/33kVTransformer

40MVAWindfarm

10km

5km

132kV Network

33kV Network

2 x 20MVACapacity Line

Part Generation Capacity MetGeneration Constraints ApplyCost of Implementation = £1-2M

400/132kVTransformer

Control Signalling

Figure 2: Active and Passive Management

Generally, if infrastructure is installed to suit the full needs of a customer, the network will be considered passive, whereas if infrastructure is fixed, but controlled by encouraging or discouraging customers, it is considered active. The UK Transmission Operator(s) (TO(s)) are considered active, one example of this on their networks is the request of large-scale generators to produce VArs to support network voltages. However it is noted that there are fundamental commercial

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drivers and frameworks in place to allow the TO(s) to earn revenue through actively managing their networks.

4.1.2 Passive Control Passive Control was the traditional operating regime of a distribution network. In the term’s true sense, it represents the ‘fit-and-forget’ system where a circuit is designed, constructed, and once energised is left to operate in isolation. Although voltages and currents may be monitored, there will be minimal follow up action in the control timeframe to alter the network based on these measurements. Whilst the entire distribution system was once operated in this manner, change has been occurring from the higher voltages downwards at a steady pace. A number of ‘basic active’ control elements are now filtering down to the 11kV system, covering areas such as fault restoration to improve customers supplies to minimise the DNOs exposure to risk (I&IP). It is now only the LV network can be thought of as truly ‘passive’, although this may be set to change as the penetration of Photovoltaics or Distributed Combined Heat and Power (DCHP) generators increase.

4.1.3 Active Control This report considers Active Control to be the system covering the monitoring, decision making and actioning stages required to manage the DNO’s Licence Obligations in a real time control timeframe (ie seconds). It is designed to proactively manage network / generator constraints currently achieved either by the DNO’s Control Engineer or through hard-wired logic. It does not include, or take the place of, statutory protection schemes, which are used for a wholly different purpose. Active Control involves a continuous cycle of: • Taking regular measurements from the live network • Performing rule based assessments, to compare the input measurements with a

predetermined network model or sequence • An output to a final control element (generator control module/interface, circuit

breaker, transformer tap changer, etc) • Feedback to report actions as complete For a relatively small country, the UK has an extremely extensive distribution network with over 290,000km overhead line and 470,000km underground cable [1]. It is therefore clear that the development of the whole system from its current position to the fully active network, won’t come overnight and must be made in a number of suitably timed steps. Current installations for active management systems on the UK networks have focussed primarily on stand-alone units, controlling a single generator connected to a single feeder. Whilst not an active network in their own right, these solutions have been used to optimise the existing network control (whether they be intertrip schemes for loadflow, or voltage

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regulators). If all active solutions are rolled out in this manner, confidence in operation will be gained, but the pace of progression may be too slow to aid forthcoming connections. To convert the network from its current state into a flexible active network it is important to consider both the requirements of a ‘stand-alone’ generation connection and that this coincides with an overall cohesive strategy for future network expansion. Furthermore, by embedding logic further into the distribution network the importance of communications reliability and the consequent risks of communications failure are reduced. To this end this report considers Active Control to be made up of three equally important stages, namely: Units, Cells and Networks, as described below:

Active Network

Active Cell(s)

Active Unit(s)

Prio

rity

Figure 3: Active Control Schematic

Active Unit An Active Unit is an autonomous constituent taking in information at a local level and issuing commands to a local device. It could be used to control network integrity, loadflow (eg down one feeder), local voltages or local fault levels either as a number of separate or as one consolidated scheme. An example of an Active Unit is a transformer Automatic Voltage Control scheme (with measuring at the VT, control in the AVC relay, and actioning with the transformer tap changer). Active Cell An Active Cell can be used to describe either a number of Active Units local to one-another - grouped together by an overriding control system, or a system that can extract information from a number of remote points. Utilising both upward and downward communications, such a system could be used to control the voltages of a group of transformers or assist in the control of loads in a ‘group’ or for load management across wide network geography. An example of an Active Cell could be several transformers (each being an Active Unit) associated by a master controller to modify AVC target voltages, achieving the most effective voltage profile for all load/generation customers. Further examples, primarily for the purposes of load management are developed and discussed in Appendices C and E.

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Active Network The Active Network would describe a number of Active Cells grouped by an overall master control unit. Such a system could be used to monitor the bigger picture, ie adjusting networks for loadflow and minimising the effect on adjacent networks (in terms of both voltages and between DNO(s)/TO). A master system could even be implemented for a range of ancillary service markets, eg system frequency, control of LV connected DCHP, etc. Network optimisers as described in Appendix E could form an important part of an Active Network.

4.2 Suitable Active Management Solutions for Implementation in SCADA

4.2.1 Overview It is likely that the implementation of active management will take a number of forms, from hardwired relays to sophisticated controllers monitoring a number of remote generators, transformers or phase-shifters. The determination of which solution best suits a particular problem will largely depend upon cost, application and geography. The advantages of using the DNOs SCADA system principally relate to the utilisation of existing communications and hardware infrastructure. Further advantages include: • SCADA is distributed throughout the electricity network (from 11kV circuit

breakers upwards). • SCADA logic is software based, therefore it can be made adaptable. • SCADA has been used in the electricity industry for over 30 years to operate

circuit breakers, or signal to control room, its principles are accepted.

4.2.2 Principles There is an increasing array of active management solutions becoming available to the DNO. Whilst presently these are tending to be confined to generation point-of-connection applications operating in isolation, greater network benefits are likely to be produced with joining these ideas together. The principles behind SCADA Active Management use are challenging, if quite straightforward: • A fail-safe system capable of operating without human intervention • A system that can be developed, enhanced, tested and implemented in a real

time environment. • A flexible software system, capable of live modifications • Logic embedded further down the SCADA architecture (at RTU level) • Reliable, communications links and RTUs • The ability to operate within specification under network storm conditions • A system with lifetime costs less than a network build solution

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4.2.3 Suitable Solutions Suitable technologies that could be implemented though the DNOs SCADA system, and the solutions that they would suit, as described in this and other reports are given in the table below.

Table 1: Active Management Solutions Investigated in this Report for Application in SCADA

Solution Loadflow Voltage Control

Fault Level

Dynamic use of the two / four season ratings of circuits

Active Unit / Cell

Thermal modelling of lines (considering solar gain, cooling effects of wind, etc)

Active Unit

Subject to the speed of operation, constraint management through tripping or issuing enable/constrain signals to the generator

Active

Unit / Cell

Load / generation forecasting Active Network

Use of ‘load shedding’ schemes Active Cell Remote control of transformer tap-change AVC setpoints

Active Cell

Voltage optimisation through Optimium Power Flow (OPF) software and the remote control of transformer tap-changer set point settings

Active Cell

DG PV: Power Voltage Control (rather than the normal PQ: real / reactive power) with the distribution generator given a voltage set-point with which to operate

Active Cell

Pre-fault network reconfiguration Active Cell

Specific OPF software applications Active Network

Active Cell / Network

Active Network

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TECHNICALLY POSSIBLE SCADA SOLUTIONS BUILDING ON THE ACTIVE UNIT, CELL AND NETWORK CONCEPTS

4.3 Changes to SCADA architectures

4.3.1 Overview To coincide with the existing SCADA systems and their capabilities, a number of solutions have been developed in line with discussions of layered Active Control above. The principles are outlined below, a more detailed discussion / development is given in Appendix E.

4.3.2 SCADA Active Unit The active SCADA ‘unit’, Figure 4, consists of a local RTU with logic functionality. The RTU can be located anywhere in the main SCADA system, and is programmed to run a number of local analogues through a set logical algorithm. Outputs are local to that RTU. It may be possible for the logic to be configurable by downloading data via the main SCADA system.

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SCAD AInput

Tim er

CTs & V Ts

Logic

(AND / O R etc)CTs & V Ts D etec tion of

abnormal sta te

C ircuit Breaker/Isolator Sta tus

D etec tion ofabnormal sta te

GD NO

C B

C ustomer

C B

A bility toA rm / Disable

‘OP EN’

‘Trip G enerato r ’

‘Start/Res et’

‘OP EN’

Local Selec tor/SCAD AO utput

A ny s ignal path may be implemen tedv ia a communication channel p rovidedit is superv ised and trip s the generato ron failure.

D etec tion ofabnormal sta te

‘System Failure’

OR

Active Unit

Figure 4: SCADA Active Unit

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4.3.3 SCADA Active Cell The active SCADA ‘cell’, is a system that will allow data to be extracted from the main SCADA network for use in a logic programme at a remote location. A GCSS (Generation Control SCADA System) is a RTU located at the DNOs generation connection, with the functionality to extract and use SCADA information from elsewhere in the system. This principle would be suitable for constraining generation at a site, at a distance from the location where the overload occurs.

RTU

RTU

RTU

RTU

RTU RTU

RTU

RTURTU

132/33kV s/stn

Modem RTU

RTU

RTU

RTU

RTU

132/33kV s/stn

Mod

em

RTU

RTU

RTU

RTU

RTU

RTU RTU

RTU

RTURTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU RTU

RTU

RTURTU

132/33kV s/stn

Modem RTU

RTU

RTU

RTU

RTU

Existing SCADAInfrastructure

SCADA Sub-System

NMS Sub-System

GCSS Port Real-timedatabase

SCADA Host

Commsto GCSS

Information fromDownstream RTUs

and Control Signaling

Standard Analogueand Digital Indicationsfrom Generation s/stn

GCSSwith Logic

Active Cell

Figure 5: SCADA Active Cell (communications to SCADA Host)

- 18 -

SCADA NetworkRTU

RTU

RTU

RTU

RTU

RTU RTU

RTU

RTURTU

RTU

RTU

RTU

RTU


SCADA Sub-System

NMS Sub-System

SCADA Host

Commsto GCSS

Micro Host132/33kV s/stn

ModemInte

rface

Por

t




GCSSwith Logic Active Cell

Real-timedatabase

Figure 6: SCADA Active Cell (communications to Micro-Host, embedded in Network)

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4.3.4 SCADA Active Network The active SCADA ‘network’, incorporates both the unit and cell principles, but also includes overriding network optimisation solutions that can improve the overall network running arrangement (be that voltage control, load management or generation constraints).

132/33kV s/stnMicro Host I

��RTU

RTU

LogicRTU

RTU

RTU RTU

RTU

LogicRTU

RTU

RTU

RTU

LogicRTU

RTU

Main ControlRoom

Host I

Standby ControlRoom

High Speed IP Link


Host II

132/33kV s/stnMicro Host II

RTU

RTU

RTU

RTU

RTU RTU

RTU

LogicRTU

RTU

LogicRTU

LogicRTU

RTU

RTU

Possible High Speed Comms Links

NetworkOptimiser

Unit Unit

Unit

Unit

Unit Unit

CellCell

Active Network


Figure 7: SCADA Active Network Proposal (incorporating Units and Cells)

4.3.5 Discussion The studies in this report consider architectures that could be implemented to achieve Active Unit / Cell / Network control through existing SCADA systems. Whilst the principles are workable with the existing systems, the finer details of each solution will have to be studied in greater depth prior to application on the network. Each SCADA solution has been developed in an attempt to best serve the network as it changes from a passive to an active system. To this end changes have been identified that can be achieved in a series of steps to ensure that the infrastructure (ie communications channels) is in place for possible future needs.

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5 TECHNICAL CHALLENGES TO THE IMPLEMENTATION OF SCADA ACTIVE MANAGEMENT

5.1 Bespoke Generation Connection Schemes

5.1.1 Overview Reliable, diverse and secure communication links are likely to be essential for many SCADA active management solutions. Owing to this, a SCADA solution (particularly active load management) is likely to be expensive at the outset with high capital costs for the provision of suitable SCADA infrastructure – communications lines, modification to Host machines, etc. If the network design for DG could become modular and repeatable, costs per connected generator would reduce as common infrastructure starts to be shared at multiple locations. The biggest problem with this analogy is in determining how long it would take for the numbers of generators to reach a suitable break-even point. The DNO has little control over the timing or amount of generation that will want to be connected into a given network area.

5.1.2 Network Design and Constraints The electricity network was traditionally designed for the connection of load. Although standard design principles are followed in each DNO, the network has been developed to meet demand, support voltage, etc. This has led to an inherently bespoke network that generally gives rise to very different operating / design restrictions when planning for generation connections in different geographical locations. This lack of uniformity leads to a number of ‘one-off’ designs in terms of both network connection and any associated constraint management schemes for generators. Conversely, a SCADA active management solution would be most suited to modular schemes, where a standard product with standard logic can be developed and implemented thereby providing a system that is cost efficient. There is some high level modular principles in the active SCADA proposals, eg a RTU with logic for local I/O constraining. However, the unique nature of the network make it difficult to split principles such as the Active Cell into smaller, simple sub-groups – as every connection and constraint solution will be different. One example of a modular, standard product that could trigger a suite of standard solutions could be if DCHP (Distributed Combined Heat and Power - domestic gas boilers with generators) or photovoltaic generators start to be connected in vast quantities to the LV network. As the complexity of active management schemes can become unmanageable once more than one generator is involved, agreement may be required at industry level on the degree of active management that will be accepted throughout the UK. It is

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worth noting that active management, in any form, will be of no use if it becomes too complicated to determine a logic path.

5.2 SCADA Limitations

The solutions outlined in this report are primarily focussed on new generation connections, where there is no existing SCADA infrastructure or communications. Whilst they have been designed to work in harmony with the SCADA network, it would be unlikely that an existing connection would have equipment (RTUs, etc) of suitable capability. Inherent limitations of the existing SCADA network (which would also be applicable if information is required through the main SCADA architecture) are described below.

5.2.1 Operating Speed The current generation of SCADA systems operate over a range of 2 seconds to 2 minutes (with typical timescales in the 5s to 45s window). Whilst some improvements can be made following significant modifications are carried out to the SCADA architecture, if speeds beyond this are required, it will be necessary to look for another alternative such as a hard-wired operational tripping system (as used for high speed protection). This is shown graphically in Figure 8. ��

��

10ms 100ms 1s 10s 100s 1000s 10,000s

High Speed Protection(eg System Stability)

Network FaultProtection Systems

ExistingSCADA Systems

Critical Systems RequiringHuman Intervention

(eg Control/Restoration)

Non-Critical Systems InvolvingHuman Intervention

(eg System Outage Switching)

Time

Network OverloadProtection Systems

Figure 8: Operating Region for Various DNO Protection and Control Devices

5.2.2 Event Driven Data and Timing Many of the current generation of SCADA systems utilised by UK DNOs were developed in the 1980s to extract digital and analogue data from the network and transfer it back to the control room. This was developed using the most available telecommunications channels of that time – typically low bandwidth, copper circuits or scanning radio systems. RTUs are typically multi-dropped and polled in a sequence, meaning that at very best they can only give a snapshot of the network at any one time. To further make best use of the available bandwidth, SCADA protocols have been designed to give digital data (alarms, circuit breaker trip signals) a higher

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priority to that of analogue data (feeder current or busbar voltages). The resultant is a system that is inherently event driven. Considering digital inputs with an 8 byte poll and a 20 byte reply, to retrieve digital data polling one RTU on a 1200 baud line takes about 0.25s. With 12 RTUs multi-dropped from the line, under quiescent conditions, polling of all RTUs takes about 3s. However, under the non-quiescent conditions following a trip, this might extend to 15s worst case to report a digital change of state. With analogue inputs, a further delay must be added due to the RTUs internal scanning, typically every 5s. Two successive internal scans may be required before the RTU reports an out of limits value, which may therefore add a further 10s, giving 25s worst case to report an analogue change of state (further detail of analogue scanning is provided in Section C.2.3). This has two main effects, firstly the analogue scanning will be a few seconds behind the live network and secondly, the SCADA system will not recognise or transmit short duration spikes or dips. A number of steps would need to be taken to improve these figures for the small proportion of RTUs retrieving generation control signals. These might include: • Modifications to existing SCADA architecture through faster and/or dedicated

communication lines (Figure E6). • More modern higher performance RTUs. • Local conversion of critical analogues to more quickly retrieved single bit digitals.

By developing a digital output from an electronic relay (preset to defined alarm limits), the analogue value from the CT is converted at a sampling rate of the order 10ms.

5.2.3 Change of Operation Although current SCADA systems are seen as a necessity for the secure operation of the network, they are not put through the same resilient, robust design process and national approvals as is carried out for, say, protection schemes. The shift from a passive to a fully active network control with many of the features embedded in the SCADA may demand a more rigid, secure solution that is currently not inherent in traditional designs. In order to ensure that the control system is suitably secure and robust, a risk assessment of the existing SCADA capabilities Vs the safety implications of failure may have to be carried out and technical recommendations backed by the industry, made.

5.2.4 Asset Functionality Newer SCADA systems have a far greater Central Processor Unit (CPU) capability, making it easier to implement the running of multiple centralised programmes at the Host level. In contrast, if installed on older SCADA systems it is likely that they would slow to an almost unusable level as the processor becomes more loaded (this would be especially problematic in a storm condition where multiple alarms can push CPU usage to its limit). Any SCADA Host based solutions may only be acceptable on the more up-to-date SCADA Host systems.

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5.3 Communications

5.3.1 Limitations Many of the newer SCADA data protocols are becoming increasingly dependent on communication bandwidth. Whereas time and effort was taken in early development to minimise these and make the most efficient use of the analogue communications infrastructure, more recent designs are being built on the assumption that there is high bandwidth availability. This is simply not the case in rural areas. The most suitable communications channels for a given voltage level would have to be assessed against a number of factors, including: availability, geography, speed, bandwidth, reliability, impact of failure and above all, the cost of installation.

5.3.2 Reliability The existing communications infrastructure principally consists of copper cable and scanning radio installed over a wide time period, from the start of the telecommunications development, to present day. As with any system exposed to the elements, deterioration occurs over time resulting in system faults. Furthermore, the diversity of many 3rd party communication services is becoming increasingly problematic. As shown in Figure 9, whilst a communications channel may be required from point A to point B (physically 20km apart), it often actually goes via the high speed router (which can be significantly further away). This can introduce significant problems if a number of channels utilise the same infrastructure such as cable trenches / tunnels, etc (re. fire in Manchester cable tunnel, 2004).

High-Speed Router

100km

20km

A

B Figure 9: Diversity Problems with Radial Communications

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5.3.3 Use of IP It may be possible to group a number of Micro-Host machines together, sharing information across a Wide Area Network using IP (Internet Protocol) methods in the same way as many standard office IT networks operate. This would allow large quantities of data to be transferred quickly between remote parts of the system, but may require diverse communications, routed via two or more paths (expensive). The expanding use of IP throughout the DNO’s SCADA network could also introduce further risks in terms of IT system security. Current SCADA systems employs secure SCADA specific protocols, with point-to-point communications over predominantly privately owned copper channels, which forms an almost islanded network that is difficult to infiltrate from outside. If however, IP were to be used across the public network, it may be difficult to install and maintain adequate firewalls to keep viruses or hackers out.

5.3.4 Communications Failure Consideration must be given for schemes in the event of a communications failure – this is a major factor as SCADA RTUs are not built like protection circuitry where loss of a channel is sensed in milliseconds and can be used to activate a circuit trip. In SCADA, if the channel fails (or if the system has to be re-booted), it may take a number of seconds to identify and the RTU will wait until the communications is restored – if the system was called upon to operate in these periods, the outcome would be indeterminate. It may be possible to cover this by various watchdog signals that would need to be polled constantly to continually verify the integrity of the communications.

5.4 Consequence of Non-Operation

5.4.1 Levels of Overload It is not easy to establish a clear priority or ranking to the role of active management against other network functions, eg protection, Delayed Auto-Reclose, transformer AVCs, etc (be that through SCADA or other means). Consider loadflow: as constraint management is not homogeneous and is dependent on connection voltage, types and levels of overload, the location of a connection, etc its importance and hence the degree of robustness would vary. For example, a scheme controlling several 132kV generation connections with potential to produce a net overload of 300% line rating would clearly have to have to be more robust than that of a single 11kV connection producing at worst, an overload 5% higher than the line rating.

5.4.2 Timing Criticality The speed requirements of SCADA control can best be investigated by looking at the implications of failure or delay on the limit of control and protection functions (ie at 140% circuit rating – typical backup line protection setting). If we assume that the

- 25 -

control device has an IDMT (Inverse Definite Minimum Time) response, the difference (discrimination margin) between the curves for both protection and control functions when an overload of over 35MVA (140% on a 25MVA rated line) are shown Figure 10.

Overcurrent Relay Discrimination Time (difference)

0

10

20

30

40

50

6014

2%

146%

150%

154%

158%

162%

166%

170%

174%

178%

182%

186%

190%

194%

198%

202%

206%

210%

214%

218%

Circuit Loading (MVA)

Ope

ratin

g Ti

me

(Sec

onds

)

Discrimination SCADA at 50sec SCADA at 5sec Figure 10: Discrimination margin between control and protection curves and impact

of slow SCADA Response

Datum lines are shown at 50s and 5s respectively. The datum at 50s indicates that providing the total SCADA system (including actioning phase at the generator) operates within this time, line loadings of up to approximately 150% could be dealt with, without resulting in operation of the backup protection. Conversely, if the SCADA system can operate within 5s loadings of over 190% could be accommodated without causing the backup protection to trip the line out. It is stressed that the backup protection systems are designed to protect from network faults, not overloads. So whilst this these times are the limits for preventing the protection to operate there will be an impact on the physical network (increased line sagging, premature ageing, etc) that will have to be considered. Realistically, it is envisaged that the control system would never be required to operate anywhere near the settings of the line protection, with operation at or safely below the declared circuit ratings (say 80% to 100%). However, as more generators connect to the network, and more constraints need to be considered, it is essential to fully consider backup provisions should the control system fail. Needless to say, the active management system must be designed to fail-safe, this is made more essential if speed of operation / reliability are significant. Therefore, a system should be in place to monitor the condition of each of the components: communications, RTU, relays, CTs, etc. A more restrictive operating regime, constraining the generator to an acceptable output may be required to be triggered if failure of any of these components occurs. This should be linked to standard

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SCADA alarms, notifying the DNOs Control Room so that they can initiate investigations and repair.

5.4.3 Network Risk and Change Management The overall design of the active management needs to ensure that the risk of customer interruptions is no more likely compared to traditional passive network reinforcement solutions, such as replacing a transformer with one of a higher rating. Network reinforcements add incrementally to the distribution system and their interaction with the distribution system is understood and predictable. In contrast active management solutions will need to be reviewed, re-configured and up-dated if the distribution system is re-configured or the system loading changes. This raises a change management issue associated with verification that that the active management solution will perform its desired function over the long term as the distribution system evolves.

- 27 -

5.5 Complexity

5.5.1 Database / Logic Management Recent developments in Host SCADA control systems (particularly at the higher voltages) offer a series of logical switching sequences that may be pre-programmed to assist the Control Engineer with network restoration during network outages. It is noted that whilst this functionality is becoming available, its use is not widespread and is currently being seen as being limited to network restoration or rapid load shedding in the event of n-2 circumstances. As network contingencies are dependent on loadings, it is envisaged that the software logic would be written and tested as part of the outage planning process prior to a given outage, and deleted from the main SCADA system once the circuit is switched back in. This avoids the temptation to use a scheme that is unsuitable for the network depending on pre-outage conditions. It is recognised that any active management solution would be expected to adhere to similar conditions.

Outage Verification(Look at network cond.)

Outage PlanningContingency

Analysis

Outage Planning

Recommendations

Upload toSCADA HostOutage

Request

Sequential SequenceDesign, Build & Test

Control Engineer

Figure 11: Use of Logical Sequential Switching in Outage Process

As with any developments, these logical switching sequences would start with the simplest constraint, then expanded to more complex schemes as confidence grows.

5.5.2 Software Logic Testing If the industry moves to more flexible software solutions, it may become necessary to look for a suitably robust design and testing regime. Rather than reinvent the wheel, it may be appropriate to adopt previously developed standards similar to those used in the process, nuclear or aviation sectors.

5.5.3 Future Uses Consideration should be given to the future of any active management equipment that may become redundant when the DNO’s network reaches an absolute limit, forcing network infrastructure to be built. The infrastructure outlined in the proposals contained within this report would be necessary for ‘traditional’ Supervision Control and Data Acquisition purposes. A more robust SCADA communications infrastructure would be required to suit the

- 28 -

more rigorous requirements of the active management model. Should the constraints no longer apply, the logic elements within the software can simply be deleted or switched off, the infrastructure will remain in place for the future. It is recognised that as the communications required for the ‘normal’ SCADA solution would generally not be as high specification as those for active management. Therefore, in this scenario there may be additional capital revenue costs that would have to be carried through.

5.5.4 Ownership There may be arguments for and against either the DNO or the generator having the responsibility for a SCADA software logic scheme. If the generator has ownership, the responsibility is passed from the DNO to the developer to update and modify their control algorithms to coincide with changes to the network. Whilst this would pass all maintenance and testing responsibility to the generator, it could be problematic in terms of security and visibility especially if the generator needs information that can only be accessed through the DNO’s SCADA network. Conversely, if the DNO had full responsibility, they would have to design, build and test any associated logic systems – all of which will have associated operational costs. Furthermore, they may be responsible for investigations or engineering support each time constraint signals are given (to justify their action). The middle ground could be sought if the DNO owned the infrastructure, but the development of logical software to feed into their generator control to be wholly the responsibility of the generation owner. As it is in the best interests of the generation owner to maximise their connection for all circumstances, the software could be tailored to meet the needs of their plant (turbine ramp rates, etc). This programme could then be passed to the DNO, for approval prior to uploading into the appropriate location(s). This system would also put the onus on the generator for investigations into spurious tripping.

5.5.5 Operational Complexity As the number of active management solutions increase on the network, it will become necessary to train operational persons (from control engineers to field staff) in the systems being implemented. This will be a significant culture change to the existing methodology, where the general perception (at least from field staff) is that the network operates purely passively. Indeed, it is highly likely that any active solution will make it increasingly difficult to take outages on the network for activities such as maintenance, construction, etc. Whilst it may be reasonably straightforward to train staff in the operation of a simple loadflow intertripping type scheme, where measurements are carried out at an obvious location and operation at another obvious location, it is less straightforward for a SCADA solution. To raise the awareness of an active management solution

- 29 -

embedded in SCADA it will be necessary to train staff in, at least, the basics of the SCADA network (as these systems are not fully understood by all staff).

- 30 -

6 CONCLUSIONS SCADA active management relies upon flexible software embedded throughout the DNOs SCADA system to control networks / generators. With the extent and diversity of the UK electricity industry, it is clear that from both a resource and cost point of view, to change the existing SCADA system to an active network management system would take a number of years. To account for this, developments would need to be proposed that could be carried out in stages, thereby giving step-by-step development, with a defined end goal. This report has identified that there are a number of modifications that would be required to existing SCADA systems to facilitate the implementation of active management. These are predominantly improvements to the telecommunications network, which may require significant expenditure. The potential advantages of using the DNOs SCADA system principally relate to the utilisation of existing communications / hardware infrastructure, and the fact that as the SCADA logic is software based, so it could be altered on a more fluid basis. But critically, this report concludes that full active management through SCADA will only be possible if: • Network constraints and the active management system to act on these are

designed to be modular and repeatable. • The inherent limitations and restrictions of the SCADA system such as speed of

operation, resilience and reliability are designed out of the active management solution.

• Suitably robust, secure and cheap communications are installed across the distribution network.

• The risks and effects of SCADA or communications failure are adequately built into the solution.

• The constraints themselves and method of implementation are simplified and standardised.

• The safety and operational implications are discussed and addressed in the active management solution.

Although these limitations apply particularly to load management, there are technical development possibilities for cases where the speed of operation, complexity and communications issues are not significant. Examples where solutions could be developed in relatively short timescales include: • Dynamic use of the two / four season ratings of circuits at SCADA Host • Thermal modelling of lines utilising site based equipment linked to the SCADA

Host (following the assessment of existing cable / line ratings at all voltages) • Local SCADA constraint management with logic embedded in RTUs • Voltage optimisation through the remote control of transformer tap-changer set

point settings (requires suitable OPF at SCADA Host and appropriate transformer AVCs)

- 31 -

• Operation of generators in PV mode: Power Voltage (rather than the normal PQ: real / reactive power) control with the distribution generator given a voltage set-point from the DNO

Finally it is noted that although the SCADA developments outlined above may be technically achievable, there may be other solutions, which may be more economically and technically suitable.

- 32 -

Table 2: General Comparison Table between Traditional, Hardwired and SCADA Solutions

Traditional Solution Hard-wired Solution SCADA Solution Overview • The construction of

network to facilitate the maximum load or generation required by connectees.

• Development of ‘hard’ logic scheme using relays, to warn then trip a generator after a time, should action not be taken.

• Installation of intertripping equipment as used in protection systems.

• Development of a ‘soft’ logic system based in SCADA software (either in appropriate RTU or SCADA Host).

• Installation of SCADA system with increased functionality at new generation sites.

Future Functionality

• Additional network capacity that may facilitate future connections or load/generation growth.

• Bespoke design – may need adaptation / replacement for new hard logic scheme and additional relays / communications.

• Once infrastructure is in place, software logic modifications can be made off-line, tested and uploaded to the relevant location.

Requirements for Implementation

• Granting of easements / wayleaves from landowners

• Installation of infrastructure, eg overhead lines.

• Communications channels between all substations where intertripping equipment is to be installed.

• Substation space required for operational intertripping relay panels substation extensions.

• Improved communication links between nodes and back to a central node (to all points of the network where data / control is required).

• Suitably located RTU(s) with logic capability.

Speed of Operation

• N/A: Constraints would not occur as the network would be designed / built to cope with all connections.

• Extremely fast: 50-500ms • Due to restrictions in SCADA system: of the order 2-20 seconds (even with improving SCADA network).

Likely Costs • Bespoke – dependent on route length and location.

• High capital outlay.

• Less capital outlay than traditional solution.

• Periodic maintenance to ensure correct operation.

• Expensive to install improved communications links.

• Once infrastructure in place, costs still associated with software logic modifications and ongoing telecommunications & maintenance.

Advantages / Disadvantages

+ Network constructed to provide 100% capacity to connectee.

+ Additional advantages in terms of system security, voltage control, fault levels and network capacity.

+ Simpler to design. + Asset life: +40 years - Can be time consuming

and costly to gain consents and build.

- Less than 100% network capacity

+Simple / inexpensive for single generation connection.

+ Proven ‘off-the-shelf’ technology.

+ Asset life: +20 years + Can be built to allow

Control Engineer to switch in/out scheme through SCADA.

- Costly / complicated for multiple connections

- Less than 100% network capacity

+ SCADA logic system will also be the main substation RTU. Any improvements in SCADA architecture could give rise to future functionality.

+ Network digital / analogues could be passed through to generator to allow them to control their output.

- 33 -

- Possible environmental implications for line build.

- Poor network utilisation in the case of windfarms, as network designed and built for maximum output.

multiple connections. - Due to speed of

operation, can be difficult to grade tripping between generators.

- Many generators cannot react fast enough to these existing requirements, and will lose connection for a constraint signal

- Crude: on/off control

- May be costly for a single generator connection.

+ May be cheap for multiple generator connections (if modular and with comms. in place).

+ Constraint (and enable) signals can be issued in ‘blocks’.

- Systems has short asset life: 10-15years

- 34 -

7 GLOSSARY AVC – Automatic Voltage Control: The system that takes voltage measurements from the network, feeds it into a controller and then gives a proportional output to a transformer tap-changer. BSP – Bulk Supply Point: The substation that connects the distribution system to the transmission system (eg 400/132kV in England & Wales, 132/33kV in Scotland). Also known as a Grid Supply Point. BW – Bandwidth: The capacity of a given channel (analogous to the width of a road for cars, ie Motorway – high BW, ‘B’ Road – low BW). CapEx – Capital Expenditure: Money spent by the DNO on infrastructure eg, overhead lines, cables, transformers, circuit breakers. CB – Circuit Breaker: A device that will carry load current but is capable for making and breaking fault current. Circuit breakers are principally used to clear faults from the network. CI – Customer Interruptions: A reportable figure to the Electricity Regulator describing the security of the system. It is calculated on the number of customers involved in an incident per one hundred of total connected customers: CI = No. of Customers Involved in an Incident x 100 Total No. of Customers in DNO CML – Customer Minutes Lost: A reportable figure to the Electricity Regulator describing the availability of the system. The figure is then calculated based on the number of customers associated with a substation, multiplied by the time off supply, divided by the total number of connected customers: CML = No. of Customers off-supply x Time off Supply (minutes)

Total No. of Customers in DNO Constraint – The condition where a DNO can request or force a generator to reduce their output due to network / load configurations. Connection Agreement: A legally binding document agreed upon between the DNO and the Generator. It specifies the operating regime of the generator (voltage limits, the net import and export of real and reactive power and the associated operating power factor, etc.). CPU – Central Processor Unit: The main computing element in a PC. CT – Current Transformer: A transducer for converting large power currents to smaller, more manageable levels (typically 1 or 5A maximum from the secondary winding).

- 35 -

DG – Distributed Generation: Any generation that is ‘embedded’ into the distribution network, see definition of DNO. DGCG – Distributed Generation Co-ordination Group: The DGCG was formed following recommendations of the EGWG (Embedded Generation Working Group). It’s remit is to focus on DG in achieving the 2010 government targets. DNO – Distribution Network Operator: One of several regional operators, responsible for managing and operating the electricity network (132kV and below in England & Wales; 33kV and below in Scotland). DNP3 – Distributed Network Protocol 3: A generic TCP/IP SCADA Protocol language, developed and adopted throughout North America. EATS – Electricity Association Technical Specification: Electrical Power Industry specification group. ER P2/5 – Engineering Recommendation P2/5 “Security of Supply” 1978. ESQC Regs – Electricity Safety Quality and Continuity Regulations 2002 GCSS – Generation Connection SCADA System. An abbreviation developed in this report describing a packaged RTU with logic functionality and capability for extracting data from another part of the SCADA network. GIS – Graphical Information System: Software used to show the geographical location of DNO’s plant and circuits. GPRS – General Packet Radio Service: A data system that allows information to be sent and received across the GSM mobile telephone network. NB: This is not GPS. GPS – Global Positioning System: Geographical location system using a number of low orbit satellites to pin-point a user to a location. GSM – Global System for Mobile communications. The overriding system that sits above GPRS - 3G is the 3rd generation of GSM. GSP – Grid Supply Point: See also BSP. HCI/HMI – Human Computer / Machine Interface: The user / control device for a SCADA system. I&IP – Information and Incentives Project: A penalisation / reward system introduced by Ofgem to drive quality of supply performance in terms of CI / CML. IEEE – Institute of Electrical and Electronic Engineers (USA): The IEEE in responsible for developing a number of standards that are used both across North America and Globally.

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Rea

ctiv

e Po

wer

(MVA

r)

Real Power (MW)

Actual Power (MVA)

θ = Power Angle: cos θ = power factor

IEC – International Electrotechnical Commission: The International agency for developing generic Power Engineering standards – used predominantly in Europe. IEC 60870-5 – Generic TCP/IP SCADA protocol language, developed and adopted throughout Europe. I/O – Input(s) / Output(s) I/T – Intertripping: A communications and interfacing system for operating a remote circuit breaker for either protection or operational purposes. IP – Internet Protocol: This protocol is responsible for moving packets of data from node to node, as designated by a four-byte designation number (the IP address). LAN – Local Area Network (re. computing network). LDC – Load Drop Compensation: System used on transformers to automatically account for voltage drop down a long line. Used in some DNOs to regulate VAr flow between adjacent interconnected transformers. Load Factor – Used to describe the availability of a generator. It is defined as the actual generation output produced divided by the total generation capacity. Real data has shown that an annual average of between 25% and 40% is common for a windfarm (exact figures are clearly site specific). LV – Low Voltage: Any alternating current (ac) voltage less than 1000V. MVA – Total Power (Mega-Volts-Amps) MVAr – ‘Reactive’ Power (Mega-Volt-Amps reactive) MW – ‘Real’ Power (Mega-Watts) NaFIRS – National Fault and Interruption Reporting System: A voluntary system for reporting large CI/CML incidents or serious accidents / incidents to the DTI. Ofgem – UK Energy Regulator (Office of Gas and Electricity Markets). Opex – Operational Expenditure: Money spent by a DNO on ‘operational’ tasks, eg staff, etc. OPF – Optimal Power Flow: A software package that can determine an optimised network running arrangement for a given electricity network. OPGW – Optical Path Ground Wire: A fairly recent development for earthwires with fibre-optics through the centre, as used on steel lattice towers.

- 37 -

OPPC – Optical Path Phase Conductor: A very recent development of a fully rated, current carrying phase conductor with fibre-optics through the centre. PC – Personal Computer: eg desktop PC. PLC – Programmable Logic Controller: A device with localised logic capability that can take a number of inputs and issue a series of outputs. PLCs can be programmed to suit a variety of applications. PSTN – Public Service Telephone Network: The analogue telephone communication system as used in the UK. p.u. – Per Unit System: A Power Engineering term, used in this report to describe voltage in terms of percentage on base. For example, an 11kV network operating at 11.0kV would be 1p.u. (100% base voltage), 10.7kV approximates to 0.97p.u. (3% low), etc. PW – Private Wire: Any communications system owned and operated by a private user. RF – Radio Frequency: The frequency range within the electromagnetic spectrum where radio signals are transmitted. RFI – Radio Frequency Interference: Any signal that may cause attenuation / destruction of a RF signal. RTU – Remote Terminal (Telemetry) Unit: The device located in a substation to extract analogue and digital information from the network, and issue control signals to specific items of plant. SCADA – Supervisory Control And Data Acquisition SCS – Substation Control Systems: The modern breed of SCADA systems for installation at GSP/BSPs utilising graphical user interfaces and some degree of automation functionality. SGT – Supergrid Transformer: An auto-transformer used to convert from either 400kV or 275kV down to 132kV (or 33kV). TCP/IP – Transmission Control Protocol/Internet Protocol: De-facto world standard for data networking. The TCP component is responsible for verifying the correct delivery of data from client to server, via suitable error prevention/correction. See IP (above) for its description. TO – Transmission Operator: The company(s) Licenced to operate electricity networks of voltages greater than 145kV in England & Wales and greater than 36kV in Scotland.

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TSG – Technical Steering Group: A subset of the DGCG that advises them on technical matters. The TSG consists of a number of workstreams, made up of key persons across the Electricity Industry (Manufacturers, Operators, Academia, etc) each responsible for specific areas of research. WS1 – Work Stream 1: Distributed Generation Status and Projections WS2 – Work Stream 2: Standardisation of Information and Solutions WS3 – Work Stream 3: Short Term Network Solutions WS4 – Work Stream 4: Micro-generation Solutions WS5 – Work Stream 5: Long-term Network Concepts and Options WS6 – Work Stream 6: Industry Skills and Resources USB – Universal Serial Bus (as used on any modern PC). VT – Voltage Transformer: A device for converting high voltage down to a more manageable level (typically down to 110Vac). WF – abbreviation for Wind Farm: A collection of wind turbines, connected to the electricity network. X/R Ratio – The ratio of network reactance to resistance (this determines the roll-off rate of dc component following a network fault).

8 ACKNOWLEDGEMENTS This project would not have been possible without the significant involvement and input from engineers both in and out of the ScottishPower group. I would like to convey my sincere thanks to the following persons. From SP Power Systems Ltd:

Angus Campbell Peter Thomas Chris Berry Bill Fulton Eric Leavy John Stokoe Alan Laird Cathie Hill Colin Bayfield Tony Dowd Paul Sands Robert Chalmers Gordon Kelly Leslie Burns Brian Rogers Mark Chamberlain Andrew Firth Ian Taylor

- 39 -

Keith Wooding Ian Tonks Steve Lloyd Steve Wood

Working in collaboration on this project, I would like to thank from Thales Information Systems: Allan Crewe

Mark Taylor Rodney Belch

Dave Roberts (Author) June 2004

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9 REFERENCES [1] ‘Electricity Distribution Price Control Review – Initial Consultation’, Ofgem,

www.ofgem.gov.uk, July 2003. [2] National Grid Technical Specification, NGTS 3.24.64, ‘Operational Tripping’,

Issue 1, June 2001. [3] Statutory Instrument 2002 No. 2665: ‘Electricity Safety Quality and Continuity

Regulations 2002’, ISBN 0 11 042920 6, Crown Copywright, http://www.hmso.gov.uk

[4] Engineering Recommendation P2/5, ‘Security of Supply’, Issue 1, Electricity

Association, 1978. [5] Electricity Association, Technical Specification Protection Approval Panel

EATS 48-5: ‘Environmental Test Requirements for Protection Relays and Systems’, Issue 2, 2000.

[6] Murray Thompson; ‘Automatic Voltage Control Relays and Embedded

Generation – Part 1’, IEE Power Engineering Journal Vol. 14 - Number 2, April 2000.

[7] Murray Thompson; ‘Automatic Voltage Control Relays and Embedded

Generation – Part 2’, IEE Power Engineering Journal Vol. 14 - Number 3, June 2000.

[8] E Paalman: ‘Voltage Regulation in Active Networks’, SP Power Systems Ltd /

John Moores University, May 2003. [9] A Collinson, F Dai, J Crabtree: ‘Identification of Outline Solutions for the

Connection and Operation of Distributed Generation’, Version 2.3, ETSU K/EL/00303/00/00/REP, January 2003.*

[10] A Collinson, F Dai, A Beddoes, J Crabtree: ‘Solutions for the Connection and

Operation of Distributed Generation’, Version F, ETSU K/EL/00303/00/01/REP, May 2003.

[11] C F Price, R R Gibbon: ‘Statistical Approach to Thermal Rating of Overhead

Lines for Power Transmission and Distribution’, IEE Proceedings, Volume 130, Pt. C, No. 5, September 1983, UK.

[12] PTI: ‘ThermalRate® System for Uprating Overhead Lines – Sales Literature’,

Power Technologies Inc., 2003.

* The DTI Projects for New and Renewable Energy are managed via Future Energy Solutions (FES). All reports under the ETSU banner are available free of charge from FES (a part of AEA Technology). Tel: 0870 190 19000

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[13] Electricity Association, Engineering Technical Report 124 (ver-002): ‘Guidelines

for Actively Managing Power Flows Associated with the Connection of a Single Distributed Generation Plant’, Working Draft, Nov 2003.

[14] M Hird, N Jenkins, P Taylor: ‘An Active 11kV Voltage Controller: Practical

Considerations’, Econnect Ltd / UMIST, CIRED 17th International Conference on Electricity Distribution, May 2003.

[15] Neil Miller: ‘Maximising the Utilisation of the Thermal Capacity of the Scottish

Transmission Network for Wind Farm Connections: Recommendations for a ‘Non-Firm’ Connection Policy’, University of Strathclyde, August 2003.

[16] Kwok-Hong Mak, Barry Holland: ‘Migrating Electrical Power Network SCADA

Systems to TCP/IP and Ethernet Networking’, IEE Power Engineering Journal Vol. 16 - Number 6, December 2002.

[17] IPSA Power, OPF Literature, February 2004. www.ipsa-power.com

- A1 -

APPENDIX A – EXISTING DNO DESIGN & CONTROL PHILOSOPHY

A.1 Network Design – General System Overview

The UK Electricity Distribution System has evolved dramatically over the 70 or so years it has been in operation. In the early days of the industry, all electricity companies had some form of distributed generation feeding and supporting local networks. In the 1930s a transmission network was established in the form of the 132kV system. As the UK load increased in the 1950s, the majority of the distributed generating stations were closed down to be replaced with larger centrally controlled units. The transmission networks were upgraded, reinforced and interconnected to suit. About this time, regional electricity companies developed and adopted various design and operational standards, for feeding principally load customers, the majority of which are still the norm. Although many of these principles vary, there are some main comparisons can be drawn. The distribution networks of England and Wales begin at 132kV (33kV in Scotland) with injection points into Bulk Supply Point (BSP) substations from the transmission system. As the 132kV network was originally developed as a transmission voltage, interconnection at this level is standard practice throughout the UK. From the 132kV network, Grid supply substations transform the voltage typically down to 33kV (or 66kV) although there are some UK DNOs that transform straight from 132kV to 11kV, providing extra capacity to the 11kV network. These feeders are, in the main, paralleled up with two radial circuits supplying a number of Primary substations, which typically transform down to 22kV, 11kV or 6.6kV. The 11kV network makes up the majority of the UK distribution system, again, typically distributing power down radial feeders to a multitude of pole and ground-mounted Secondary substations. These transform from 11kV to 400V, although in sparsely populated areas there are DNOs employing pole mounted transformer that step straight from 33kV to 400V. The extensive 400V network supplies Low Voltage (LV) load customers, providing three-phase and single-phase voltages within existing statutory limits. Whilst most operate radial circuits, some DNOs, eg SP Manweb, chose to operate some or even all of their 33kV, 11kV and LV networks interconnected. Rural 11kV and LV supplies are almost exclusively radially fed.

- A2 -

132kV

33kV

6.6/11kV

LV

P o w e r F lo w

Figure A1: Interconnected Network Structure

As mentioned above, historically, networks were developed to feed local communities, fed from local generation. The networks developed upwards in voltage level as the load grew, but since the development of the transmission systems all now operate top-down (ie from 400kV down to LV). All this has happened in the last 50 years or so, but the network continues to be designed bottom-up, (ie for a 20MVA connection, network designers will look for the most appropriate network in terms of load capacity – in this case either a 33kV or in highly loaded areas, a 132kV connection). As the distribution network was originally developed to permit load connections, the supply security evolved to be proportional to the number of customers connected, ie an urban network would have more circuits and increased redundancy to that of a rural network.

A.2 DNOs Obligations

To accommodate any generator (or load) the UK DNOs must comply with a number of regulations and standards as part of their Licence Obligations. Some of the principal factors are the design and operation of a network that will: • Protect from network faults • Limit the effects to customers of network faults (reduce CI/CML) • Ensure integrity of assets (eg prevent overloads, maintain statutory clearances) • Maintain Statutory voltages • Ensure the operation of equipment within its fault rating • Assist Transmission Operator(s) (TO) with frequency response

A.2.1 Fault Protection Limiting the effects of a network fault. The rapid disconnection of a fault to limit fault energy and reduce the risk to personnel and the public. The protection is

- A3 -

designed such that when a fault occurs the minimum number of customers are disconnected, and the disconnection occurs rapidly to minimise damage to plant and maintain the integrity of the remaining network.

A.2.2 Network Performance Reducing the time a customer is off supply (due to a network fault). Traditional techniques for fault location, isolation and network reconfiguration following a network fault often led to customers being off supply for long time periods. To limit CI and CML figures, many DNOs are in the process of implementing some strategic remote control, protection and automation schemes to reconnect customers following a fault, further limiting the impact on customers. There is a clear driver to DNOs to improve on this performance year on year.

A.2.3 Loadflow The thermal rating of lines and cables. Current flowing through the lines causes heating losses; this can lead to an increase in conductor sag or premature insulation degradation. If thermal limits are exceeded, statutory clearances on overhead lines may be compromised and / or plant could run a risk of permanent damage. DG connecting onto a circuit, will increase the loadings down a feeder, and whilst this may not be a problem for an intact network, when circuits are taken out for operational work / maintenance, reductions in a generators export may be necessary.

A.2.4 Voltage profiles The impact on Statutory Regulations and effects on DNOs ‘other’ customers. Under the Electricity Safety, Quality and Continuity Regulations 2002 the DNO must maintain voltages within statutory limits. Failure to comply could result in damage to customer’s equipment and any associated claims against the DNO. The connection of DG can have the effect of lifting voltages at the point of connection when exports are high and dropping voltages at times of low export. Consequently, the DNO has to compensate for the voltage change to maintain Statutory limits to all customers connected to the system.

A.2.5 Fault Level Ensuring the DNOs design fault ratings are not exceeded. As there is no over-fault rating for switchgear fault levels, once exceeded, there are risks to the safety of public and personnel as a result of equipment failure. With an increase in rotating plant (ie the generator), there is an associated increase in network fault infeed. As the system is designed such that fault levels are not exceeded under any conditions, restrictions on the number of turbines permitted to run (limiting the fault infeed), may apply.

A.2.6 Frequency Assisting the TOs with system frequency. Traditional assistance to the transmission operators has involved the provision of load shedding and voltage reduction schemes, which can be called upon should the loss of a major ‘scheduled’ generator occur (re. New York fault, August 2003). However, as the penetration of embedded generation increases, and more and more of the large centralised generators

- A4 -

become decommissioned, the control of system frequency using DG may have to become more of a priority.

- A5 -

A.3 Changes in Network Design for the Connection of Generation

A.3.1 Overview The local network topology is an essential consideration in the connection of any generator to the DNO. Whilst this is a factor for all generation technology types, it is particularly prevalent in the case of wind. Generation developers naturally site their windfarms in the areas of high average windspeed, ie on hillsides in mountainous areas, but for the DNO, these are the traditional low load areas, with few customers and associated ‘weak’ electrical networks. In order to facilitate these connections, meet Legal & Licence compliance and provide a least cost option, the DNO often has to modify their standard designs, stretching their network both in terms of plant ratings and network complexity. In order to connect any form of embedded generation, detailed modelling is required. Historically, the network design at 33kV (on radial networks) and 11kV has not required such level of detail and complexity to calculate the impact on loadflow, voltages and fault levels. The existing methodology is to design a network capable of facilitating 100% connected generation export for a fully intact network – consequently, constraints should currently only apply when the network is configured abnormally (either through planned or unplanned circuit outages). However, as the number of generation connections increases and network capacity becomes restricted, more and more constraints may start to apply under system ‘normal’.

A.3.2 Loadflow Solutions Due to restrictions in the ratings of lines and cables under outage conditions, a number of systems have been installed to existing generation connections giving the DNO the ability to trip the generator. This practice, using a series of hardwired ‘operational’ intertripping schemes, charged to the connecting generator is still standard design policy, albeit dramatically increasing the complexity of a network. It is noted that on networks with limited generation connected, the constraints are generally subjected to just a single generator and there is no interaction between sites, guidance to DNOs is provided in ETR 124. Generator constraining for limiting loadflow can take many forms, some examples include: • All off intertrip – A signal is sent to open the connecting circuit breaker of all

generators connected to a feeder, or network group (in the case of an interconnected network).

• 33% / 66% reduction signals – Signals are sent to a generator to cut their export first by 1/3, then, if necessary, by 2/3. If the generator fails to do so in the allotted time, a trip signal is sent to open the connecting circuit breaker.

- A6 -

Example Scheme Figure A2 shows a typical load constraining scheme. The generator connection is 32MVA onto a mixed cable / overhead line 33kV circuit. For an intact network with maximum generation, loadflow studies have shown that the load is almost equally divided between the two 33kV feeders. When one circuit is switched out, either for maintenance or due to a fault, the remaining circuit is clearly insufficient to carry the maximum generation capacity. To ensure the circuits do not exceed their rating, a hardwired overload system has been installed. Basing the settings on the Summer rating of the line, if current >315A (18MVA) is seen on either feeder, a signal is sent to the generator, telling them to reduce. This reduction signal is gated through a timer such that if action is not taken within 1 second, the DNO will trip the connecting circuit breaker. If the current exceeds 385A (22MVA) per feeder for more than 3 seconds (at any time), the DNO will automatically trip the connecting circuit breaker. This is a relatively simple, reliable and inexpensive solution as, being installed at the connecting substation, there are no associated costs for intertripping equipment and communications channels. It provides slightly more flexibility than a standard tripping scheme, allowing all generators to stay connected, but at reduced output, for an outage condition, particularly useful in the case of a windfarm.

18MVA Line Rating 18MVA Line Rating

32MVA Generation Capacity

OverloadRelay

OverloadRelay

Set to 18MVA

Set to 18MVA

11kV

33kV

33kV

33kV33kV

TMTM

Figure A2: An Example of Hard-Wired Load Constraining

Whilst simple for a limited number of connections, the use of hard-wired intertripping schemes is not ideal, creating design restrictions for multiple generators. As each further connection comes along, the intertripping schemes must be revisited and modified to suit. For example, if another generator decides to connect to an adjacent busbar, modifying the loadflow (ie causing more than 18MVA to naturally flow down one of the two 33kV circuits from the initial generator), the first generator may receive constraining signals on a more regular basis.

- A7 -

A.3.3 Voltage Profile Solutions The only true active control on the existing network is the voltage profiling of the 132kV, 33kV and 11kV networks using Automatic Voltage Control (AVC) schemes in association with transformer tap-changers. These schemes compare the local voltage to a set point, then alter the number of transformer windings, to either step up/down the primary to secondary ratio thereby altering the voltage. The majority of Grid and Primary transformers control their volts automatically via standardised AVC schemes, with the only occasion where this is not practice, is in some heavily urbanised areas where a high network density ensures tighter control of the network voltages.

Table A3: Current Voltage Control Practice on the Network

Name Location Description SCADA / Local

Automatic Voltage Control (AVC)

132/33kV Transformer Tap Change Scheme

• Range of settings dependent on the tapping range of the transformer

• Set to control 33kV volts • Can have limited SCADA interface (3% voltage

reduction, etc) or possibly remote tapping • Can be set to operate at fixed power factor • Located at every 132/33kV Grid Substation

Auto Local + some

SCADA

Automatic Voltage Control (AVC)

33/11kV Transformer Tap Change Scheme

• Range of setting, dependent on the tapping range of the transformer

• Set to control 11kV volts • Load drop compensation may be used • Other schemes employed to control circulating

VArs on paralleled transformers • Located at every 33/11kV Primary Substation

Auto Local

In-Line Voltage Regulators

11kV Feeder • Two single-phase regulators connected in open delta

• Set to control line voltage on 11kV network • Bandwidth can be monitored to harmonise with

generators and AVC at Primary Substation • Very few connected to network

Auto Local (poss.

SCADA use)

Manual Tap Changer

11/0.433kV Transformer

• Manual, off supply tap changer • Typically only altered to ensure voltage profile

down a feeder remains within statutory limits

Manual Local

Capacitors At substations or on network

• Inject VArs to network to raise voltages • Limited use throughout UK

Fixed (some can be

switched in steps)

A further feature used by a number of DNOs for their networks is Line Drop Compensation (LDC) [6-7]. This simulates the voltage that would be received by a remote radial customer, by measuring the current flowing through the transformer and accounting for the volt drop on the network. For interconnected networks LDC is used in a slightly different manner, exploiting the VAr limiting capabilities of negative reactance LDC to ensure tapping synchronism between paralleled transformers. Both variants have been designed for the ‘top-down’ flow of power

- A8 -

with the remote end voltage being lower than at the source (the transformer). Problems can arise using true LDC when a generator causes the receiving end volts to rise, or in the case negative reactance LDC, as the power factor varies. Furthermore, the age profile of transformers across the UK can raise further issues as some of the older units on the system are fitted with tapchangers that are incapable of operating in ‘reverse’ power mode. Transformer AVC schemes are tried and tested on the Distribution network. They are favoured by the industry as they control at the source, independent of any communications channels, thereby ensuring that voltages remain within the DNOs Licence Obligations. Challenges for Voltage Control Under the DNOs Licence Obligation, voltages at which customers are connected must be kept within strict limits: 132kV ±10%, 33kV / 11kV ±6% and 400V (three-phase, 230V single-phase) +10% -6% [3]. The LV network is designed to make efficient use of these tolerance bands, Figure A3. For this to be possible customers connected close to the transformer receive voltages of around 250V (for no load), and customers furthest from the transformer receive around 220V (under full load). This design has an impact on the rest of the system as whilst Grid (132/33kV) and Primary (33/11kV) transformers are typically fitted with automatic on-load tapchangers, Secondary transformers (actually 11/0.433kV) are not. Due to the sheer number of secondary substations, it is unfeasible to consider manually tapping these transformers as a method of controlling voltage, hence, control is done at the voltage levels above. Transformer tap steps and AVC bandwidths are such that the tap changers on the 33/11kV transformer operate more than those on the 132/33kV transformers. This adds additional complexity for the DNO when connecting DG to the 11kVnetwork. A generator requires its source voltage to be as low as is possible so that they stay stable under maximum power export without causing excessive voltage rise. As generators begin to populate the 11kV network feeders (as shown in Figure A4), rather than connection directly into the Primary substation, they have a greater influence on the local LV voltages (where the DNO has no voltage control means). Existing connections may rely on the generator importing VArs at times of high power output to minimise this voltage rise, an effect that is both costly to the generator and inefficient. Whilst suitable for low levels of generation, it does challenge AVC performance and increases line losses in areas of high generation penetration, low load, with transformers being a net exporter of power, but an importer of VArs.

- A9 -

33kV 33kV 11/6.6kV 11/6.6kV LV132kV132kV400/275kV

1p.u.

0.98

0.96

0.94

0.92

0.90

1.10

1.08

1.06

1.04

1.02

Upper Statutory Limits

Lower Statutory Limits

Figure A3: Example Voltage Profiles for a Load Connection

33kV 33kV 11/6.6kV 11/6.6kV LV132kV132kV400/275kV

1p.u.

0.98

0.96

0.94

0.92

0.90

1.10

1.08

1.06

1.04

1.02

Upper Statutory Limits

Lower Statutory Limits

Figure A4: Change in LV Voltage Profile with the Connection of a Generator at 11kV

- A10 -

In-line 11kV Voltage Regulators To achieve satisfactory voltage control on weak 11kV networks, PowerSystems are undertaking trials using a pair of in-line voltage regulators connected and commissioned near to the point of connection to an adjacent windfarm [8]. To ensure simple, reliable operation the regulators are set to operate without dedicated communication equipment but work together with the wind generator and the voltage control at the local Primary substation. To achieve this each device has to operate on a stand-alone basis and within its own pre-defined set of parameters. It is set up to be approximately three times faster than that of the Primary transformer, therefore ensuring that it is the voltage regulator and not the 33/11kV transformer that will react to any voltage changes caused by the wind cluster.

33/11 kV Transformer

Voltage Regulator

Load Area

Customers on Spur line

Main Line

Spur Line

M600 kW

850 kW

850 kW

Wind Turbines

Main LineNormal split point

Figure A5: 11kV In-Line Voltage Regulator Scheme Overview

The inherent advantage to this solution is that the regulator is effectively a stand-alone unit, independent of communications (notoriously poor in this rural area). However, there are operational reasons why communicating with the voltage regulators would be advantageous. In its simplest form, the DNOs Control Engineer should have the ability to remotely switch the regulators in and out of service, allowing the modification of network split points, affecting the load distribution, without driving the voltage regulator outside its operating limits. The next development of this system is for a trial to communicate using a RF signal between the generator, the voltage regulator and the local transformer AVC panel, in a bid to further improve the export capabilities of the generator and improve voltages.

- A11 -

A.3.4 Fault Level Solutions Switchgear is built and ‘type tested’ to a given fault level limit. This is a cut-off point beyond which, the manufacturer ceases to guarantee the units integrity on fault breaking. Managed through thorough network design, throughout the UK it is practice to design systems so that fault levels are kept below strict design fault level ratings. There are significant advantages to operating a network close to maximum fault levels, a high fault level: • Keeps the quality of supply (harmonics, voltage flicker, etc) to customers within

limits, given the ever-increasing levels of connected disturbing load. • Ensures protection schemes operate quickly with high discrimination from the

effects of connected load. • Reduces network losses. However, the closer a network is to this limit, the more difficulty there is in connecting generation. The electricity network is carefully designed to ensure that fault levels are not exceeded. This may be achieved by maintaining a number of ‘open points’, employing reactors throughout the system or other solutions deemed applicable by the DNO’s system design.

A.4 Electricity Network Control

A.4.1 Overview All DNOs operate their 132kV, 33kV and 11kV networks from Control Centres staffed 24-hours per day, 7-days per week by Control Engineers. Network control relies on the fact that there can only ever be one person in control of that network, hence it is necessary to define and segregate Control Boundaries between voltage level, circuits or geography, be that central control or on-site ‘field’ control. Defined procedures must be followed in order to transfer control from one person to another, involving suitable operational authorisation levels and an associated logging procedure.

A.4.2 Network Control Practices for Embedded Generation Connections As the number of embedded generation connections increased, there has been little operational change in the way the network is managed. Like the origins of the network design, the distribution network control maintains an emphasis on load connections, and under existing Licence Obligations, DNOs are reluctant to actively modify their networks to suit the needs of a generator, particularly if this is at the expense of existing load customers.

- A12 -

A.4.3 Control Room Experience of Existing Systems Most DNOs are not contracted to act as the controlling body for the vast majority of customer owned networks. There is a clearly defined Control Boundary agreed between DNO and customer to explicitly show who has the controlling responsibility of a section of network. Because of this, many DNO control rooms are uncomfortable with directly tripping a customer’s circuit breakers (load or generation) without first requesting a reduction in output (as it crosses Control Boundaries). Instead, the preferred method of automatically managing load constraints would be for a system that would issue a latched signal to the generator requesting a reduction, but backed up by a slugged trip signal to the DNOs interface circuit breaker. The latching is important as it will prevent the generator from continually hunting (ie tripping part of the site – removing the overload, then as the overload disappears, the generator immediately goes back to full output re-causing the overload – constraint management operates, etc, etc). It has been suggested that the latching should only be reset by the DNO’s control engineer. The benefits of such a system are: • The DNO / customer Control Boundary remain clearly defined. • The customer can use a management system that will determine and issue

signals in the optimum way to suit their network / generators. • Backup is provided with a trip signal (the system can be built fail-safe). It is further noted that the DNOs control room should have the facility to both remotely switch any active management system in or out, and force a constraint on – as there may be times when manual intervention is necessary (eg specific outages or network configurations). Anecdotal evidence has indicated that the reliability and diversity of existing communication channels is questionable. This alone has led to a significant hesitance in the implementation of any SCADA based active management solutions using such channels, particularly if the speed of operation is a priority. Finally, it is noted that the network is not static, varying continually depending on load (by the second), time of day / year, outages and network faults, hence there may have to be significant involvement in constantly verifying whether the active network solution is still suitable and current.

- B1 -

APPENDIX B – EXISTING SCADA SYSTEMS

B.1 Overview

SCADA, refers to the communications and control system from a remote substation to the control room. It is used to give network transparency to the Control Engineer, allowing them to make decisions on how the network is to be run. In order to facilitate the control features currently used in the DNOs, the SCADA architecture has evolved reaching out into remote parts of the network, returning data to centralised hubs. As the electricity systems and communications technology have developed, more and more sophisticated SCADA systems have been incorporated into existing and new substations providing Control Engineers with ever increasing on-site monitoring and control capabilities. There are three primary SCADA signalling types (Figure B1): • Analogue Data – Currents and Voltages measured from on-site transducers

(CTs/VTs). • Digital Data – Eg Circuit breaker, isolator position indications, ‘protection

operated’ flags, etc. • Control – The facility to remotely open or close a circuit breaker or motor driven

isolator.

Tx Prot.

132kV/33kVTransformer

Tap Change Relay

33kV Circuit BreakerRemote Operation

(Control)

132kV Circuit BreakerRemote Operation

(Control)

ProtectionOperated(Digital)

Tap ChangePosition Indication

(Digital)

33kV Circuit BreakerStatus Indication

(Digital)

132kV Circuit BreakerStatus Indication

(Digital)

Feeder Current(Analogue)

Feeder Voltage(Analogue)

Figure B1: Example of SCADA use for a Simple Transformer Feeder

SCADA was firstly developed for the higher voltage networks, where the impact on adjacent circuits or number of customers that could be reconnected following an

- B2 -

incident are most significant. This offered the most cost-effective solution at times when the equipment was in its infancy. As it became cheaper and more readily available, SCADA was introduced further down the system onto the lower network voltages. Figure B2 graphically depicts the extent of SCADA in the UK for DNO substations at each voltage level.

GridSubstations(132/33kV)

PrimarySubstations(33/11kV)

SecondarySubstations(11/0.415kV)- Ground Mounted Only -

132kV

33kV

33kV

11kV

11kV

LV

* Telecontrol available on all Circuit Breakers * Analogue data available on all feeders * Digital Alarms and Indications available for virtually all equipment * Comprehensive and robust communications links * Faults highlighted via Protection Operation indications sent to Control Room

* Telecontrol available on most Circuit Breakers * Analogue data available on all feeders * Digital Alarms and Indications only available on newer equipment * Faults highlighted by indications of Protection Operation sent to Control Room

* Telecontrol available on most Circuit Breakers * Analogue data available on the majority of feeders * Digital Alarms and Indications - as above * Faults - as above

* Telecontrol available on Circuit Breakers (post 1985) * Some Analogue data available at Primary substation * Most Digital Alarms and Indications available * Fault highlighted to control room by the opening of a CB (where available)

* Little / No telecontrol * Little / No Analogue data * Little / No Digital Alarms and Indications * Customer reports a ‘no supply’

* Noremote info.

<1% of UK substations

Supplying approx. 22,000 customers per substation

Approx. 4.0% of UK substations

Supplying approx. 3,000customers per substation

Approx. 95% of UK substations

Average of Ground Mounted andPole Mounted substations supplyapprox. 40 customers per substation

Figure B2: Overview of the SCADA for each Voltage Level (ignoring Pole Mounted

Secondary Substations – inherently no control/indication options) The control attributes associated with substations at voltages below 33kV reflect the age profile of switchgear on the network. In general, the majority of current and voltage analogues at the Primary substation are sent back to the control room, however it is only the newer substations that have digital indication information such as CB position, tap-changer position, etc. Similarly, remote opening and closing of circuit breakers, especially at 11kV, is only available on more recent substations (mid 1980s onwards), with the remainder reliant on Operational Personnel performing local switching under the instruction of a Control Engineer.

- B3 -

B.2 Generic SCADA System Architecture

B.2.1 Overview The SCADA currently in place throughout the UK is a mixture of 2nd or 3rd generation systems. The 1st (developed in the 1960s) used an amalgamation of old telephone technology and discrete components to take ‘change-of-state’ alarms back to a local, manned substation. With second generation systems (1970s technologies, implemented throughout networks in 1980s), RTUs are polled every x seconds, for a set number, y, milliseconds, with information extracted to provide the control room of a snapshot of the network at that instant. The majority of the time this will contain purely analogue information, feeder currents, busbar voltages, etc, and a priority order is used so that any digital information (CB change of state), trips, etc, goes to the front of the ‘data queue’. It is then sent at the start of the next poll. Third generation systems (utilising 1980s technology, implemented throughout the networks in 1990s) operate on the basis of ‘exception’ reporting. In this system slave RTUs are polled in the same manner as the 2nd generation systems, but asked whether they have anything to report. The typical response would be a short message stating ‘no-change’, however, if there are any changes, a significantly longer message (containing RTU location, degree of change and time-stamp information, but to name a few) must be transmitted back to the master Host machine. Under ‘normal’ network conditions, this is an efficient system avoiding needlessly cluttering the data channels, but under storm conditions or at times where the network experiences high loading rates of change, it can be significantly more bandwidth hungry. NB: a full 32 channel analogue on a 2nd generation system will take 64 bytes, in contrast, a 3rd generation equivalent will require closer to 500 bytes! The majority of the DNOs have centralised high availability SCADA systems to control their High Voltage (>1kV) networks. The more recent installations have made use of modern communications technology and split the two halves of their high availability central servers (dual) on high bandwidth LANs. Some DNOs have distributed data acquisition that has been put in place because of restrictions in their RTU communications infrastructure rather than any strategic reason. In some cases the 11kV and the 132/33kV are different systems from different suppliers. In the case of some separate 11kV systems the data acquisition can be carried out by the 132/33kV system and passed through to the 11kV system.

- B4 -

Main ControlRoom

Host I

Standby ControlRoom

High Speed IP Link

Host II

RTU

RTU

RTU

RTU

RTU

132/33kV s/stn

Modem RTU

132/33kV s/stn

Mod

em

RTU

132/33kV s/stn

Modem RTU

132/33kV s/stn

Mod

em

RTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU RTU

RTU

RTURTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU RTU

RTU

RTURTU

RTU RTU

RTU

RTU

RTU

RTU

RTU

RTU RTU

RTU

RTURTU

RTU

RTU

RTU

RTU

PW Lines PSTN Lines

Lower bandwidth, separate channels

Point to PointCommunications


High availability,high bandwidth

channels

TriangulatedCommunications

PW Lines

Figure B3: Generic SCADA Overview from RTU to Control Room

The majority of signals operate bottom-up, with over 90% of data being transmitted from RTU back to the Host machine. At the higher voltage sites (eg 132/33kV), data concentrators may be employed to collect information from a number of downstream RTUs. These are linked to modems so that when data comes into the unit, the address identity is checked - if it has come from a downstream ‘slave’ unit, it is passed straight through to the Host machine. There is no provision in the existing devices at this level for logical programming. The communications tend to be more secure the higher the voltage, with key sites utilising two or more diverse routes. At the very top-level, triangulation may be utilised to allow for multiple faults on the communications system. The operational functionality used for networks from 132kV to 6.6kV may consist of the following (NB: 11kV and below has some restrictions where telemetry is not installed):

• SCADA – data acquisition, data processing and remote control • Alarm processing • Historical data • Sequence / rota disconnection / emergency demand control switching • Graphical HCI with schematic drawing • Switching schedules and safety documents • 132/33kV Network Power Applications (limited DNOs)

- B5 -

Further to these control functions, there are several support functions that may be extracted from the control-room interface software including:

• Outage Management • Interface to the corporate GIS system for diagram updates • Interface to corporate applications such as Asset Management, Settlement

Systems, Load Analysis and Network Planning • Fault logging and customer/network interface systems • Interfaces to NaFIRS systems for fault reporting: these are the central UK

systems

B.2.2 Age profile, intelligence, capabilities and functionality of the RTUs The DNOs began equipping the 132/33kV networks with current generation of RTUs in the early 1980s. This process was largely complete by the end of that decade. Generally the RTU population purchased in that period has not been replaced. Where some DNOs have started to replace these, because of compatibility reasons with their central SCADA system, they have often retained the existing RTU protocol. More recently, secondary network automation and remote control schemes have been implemented using modern, small, low cost RTUs. One example of this is scanned autonomously by a Data Concentrator RTU and can appear as a single RTU to the central SCADA system. Intelligent relays have also appeared in large numbers with the capability to supply large amounts of data following a disturbance. The RTUs used by DNOs typically become cheaper, simpler and with less features the further they reach into the rural networks.

The protocols used are mostly proprietary ones from the RTU manufacturers. Typical ones are:

• Thales (Ferranti) proprietary, with various generations • Schneider (Westinghouse) proprietary • DNP3 (de-facto standard) • IEC 60870-5 (standard) • Others including:

• GEC* proprietary • Remsdaq (a form of DNP3) • Radius • Newlec proprietary

The functionality varies greatly, however, the following is fairly common:

• Time tagging of switch changes and alarms with up to one millisecond accuracy (typically 10ms)

• Measurements of analogues with alarm limit checking • Digital outputs with configurable pulse duration • Intelligent relay connectivity

* GEC – General Electric Company (now owned by Areva)

- B6 -

• Programmable. Whilst not an extensively used system, logical sequences can be programmed into some RTUs and executed at run time.

B.2.3 Communication Channels UK DNOs operate their networks over a range of diverse geographical topologies from built-up urban to dispersed rural networks. Their SCADA infrastructure was developed accordingly, utilising the most available and cost effective communications channels in the area. This has led to varied communication channel infrastructures with each DNO using a different system to the next. The communications used (generally) have the following characteristics:

• Analogue circuits • Relatively slow: 600, 1200, 2400 baud • ‘Multi-dropped’ with around 10/15 RTUs per line • A combination of private wire (eg protection, rented copper, rented fibre) and

low bandwidth privately owned/operated radio Bandwidth Requirements The amount of data required to and from each substation is increasing. When SCADA was first introduced the communication protocols were designed to best utilise existing, available communications channels and maximise the limited CPU capability in the Host machines. With this in mind, the protocols were an extremely efficient, compacted version of their modern day counterparts, allowing communications over slow, low bandwidth Public Service Telephone Network (PSTN) or Private Wire (PW) lines. Changes in protocol have developed with advances in computing technology, and as the price has dropped and availability increased, systems have become faster and crammed with more features. These features require a significant increase in bandwidth and it is now at the stage where many of the newer protocols (eg IEC 60870, DNP, etc), can no longer adequately perform over PSTN/PW. To this end, the protocols must be converted or redesigned for each specific DNO to meet the capabilities of their available communications infrastructure. In addition to the control and indication signals, real-time data is brought back to the DNO for purposes such as operational planning, investment and post fault analysis. Increased regulatory pressures on the quality of supply are likely to increase this further with the addition of voltage imbalance and harmonic data to allow the DNO to fully monitor customer’s supplies. In order to address these issues it is essential that DNOs take a critical look at their communication infrastructure, the capability and the available options for improvement. Communications Channels Reliability The existing communications infrastructure principally consists of copper cable installed over a wide time period, from the start of the telecommunications development, to present day. As with any system exposed to the elements, deterioration occurs over time resulting in system faults. As the DNOs require communication channels over a wide geographical area, the length of which

- B7 -

coupled with the extremely high reliability requirements often leads to difficulties in attaining a truly secure service. Many copper circuits have varying levels of performance with regards to their behaviour during disturbances caused by overvoltages. It has been shown that the fault tolerance is best achieved using optical fibres, which are not widely available, particularly in rural areas. It has been highlighted on many occasions that securing effective, duplicate, diverse and reliable rented channels in, again, rural areas (where many of the current renewable generators are located) are both difficult and expensive.

- B8 -

Table B1: Overview of Existing Communications Channels

Channel Operator Advantages Disadvantages Rented Digital (BT Megastream – on Fibre Optic, Microwave or Copper)

• High bandwidth – able to cope with vast amounts of data

• Diversity at higher voltages

• Fast bit rate (2Mbps upwards)

• Fibre Optics into the substation offers the safest, most secure solution for ‘hot sites’

• Microwave, useful across waterways / mountainous areas – no requirements to install new cable

• Costly - Only installed on few Grid Substations

• Can be affected by local faults (including power outages)

• Cost of installation, paid to operator (tens of thousands to hundreds of thousands)

• Line rental costs (approx. £22k/year/circuit – length dependent)

• Microwave can be unreliable in poor weather conditions

Rented Copper (PSTN)

Telecomms operator (eg BT, Thus, etc)

• Large number installed for Public Telephone Network

• Adequate bandwidth for older protocols

• Age of assets • Slow bit rate (2400 Baud) • Poor Reliability in rural

areas • Slow operator reactance

to system faults • Risk of failure under fault

conditions (ie when needed most!)

• Line rental costs (approx. £3k to £8k/year/circuit – length dependent)

Radio DNO • Relatively cheap • Licensed Radio: Installed

for a limited number of Secondary / Primary Substation Automation schemes

• Limited bandwidth / communications speed (restrictive on no. of downstream RTUs)

• Can require many repeaters for mountainous areas

Private Digital (eg OPGW or Fibre Optic wrap on transmission towers

DNO • As Rented Digital • DNO has responsibility

for channel quality / reliability

• Typically more than one feeder into substation – therefore channel diversity

• Currently, limited geographical deployment

• Only deployed on earthed tower lines

Private Copper DNO • Installed across the network for a variety of applications including pilot wires for protection schemes – possibility to multiplex or uprate for use as digital channels

• Channel quality monitored to ensure protection healthy

• Slow bit rate for multi-dropped lines (1200 Baud)

• Age deterioration

- B9 -

• DNO has responsibility for channel quality / continuity

- B10 -

B.3 Protecting and Controlling the Network

Although the six obligations listed in Appendix A are very different in nature, there are three common themes that tie them together. As with any control system, be that manual or automatic, passive or active, there will be some form of measurement, a thought process where a decision is made, and an action taken where necessary to mitigate a risk, Figure B4.

Decide

Measure

Act

Y

N

Figure B4: High Level Control Philosophy

Consider a basic protection scheme, Figure B5, here our simplification represents: • Measure Measure feeder current using a Current Transformer • Decide Compare current measurement with protection setting using a

Protection Relay • Act Protection Relay to operate Tripping Relay which Opens a Circuit

Breaker once signalled

Ifault

ProtectionRelay

TrippingRelay

Figure B5: Example using a Simplified Protection Scheme

Communications Of course it is essential to also consider the communications channels that allow the signals to feed from one unit into another, these are simple for a local protection circuit (using hard-wiring), but can be much more challenging for a network controlled over a distance.

The typical speed of operation for a protection system (Current Transformer to Circuit Breaker) would be of the order 100-500 milliseconds.

- B11 -

The principles that lead to the different approaches, ie manual / automatic, speed of operation, redundancy, etc are associated with the priority to the system and the associated risk of failure. Table B2 gives a ranking for various items of light current equipment widely used on the UK electricity network.

- B12 -

Table B2: Merit / Priority Order for Protection & Control Equipment

Rank Relay Application Driver for Ranking 1 Protection Relay

(inc. ‘Protection’ Intertripping)

• To remove faults from the network

• To protect life and limb

Legal & Licence Conditions (ESQC Regs [3])

2 Under-frequency Load Shedding

• To rapidly disconnect groups of load should the UK generation output fail to meet the load demand (following notification from the Transmission Operator)

Distribution Code

3 Voltage Control • To ensure voltages stay within Statutory Limits

Legal & Licence Conditions (ESQC Regs)

4 Auto-Reclose (eg 132kV)

• To re-energise a line following a fault (on the assumption that a high proportion of overhead line faults are transient)

Licence Conditions (P2/5 [4]) also financial implications: Network Performance (CI / CML penalties) High numbers of customers and high network risk (depleted network)

5 SCADA Indications, Alarms & Control

• Visibility of network currents / voltages

• The ability to remotely operate an item of plant

To allow the DNO to meet its Licence obligations (ie to monitor the network and ensure circuits do not become excessively loaded).

6 Auto-Reclose (eg 11kV)

• To re-energise a line following a fault (on the assumption that a high proportion of overhead line faults are transient)

Network Performance Penalties (CI / CML)

* Embedded

Generation Constraining (‘Operational’ Intertripping)

• To limit a generators output such that circuit or asset (eg plant) ratings are not exceeded

To ensure that line sags do not reduce clearance and that equipment is not prematurely aged. Generator is constrained off if failure occurs.

- B13 -

*It is not easy to establish a clear ranked position for the role of operational intertripping. As constraint management is non-homogeneous and is dependent on connection voltage, types and levels of overload, the location of a connection, etc its relative position would vary. Ie in the case of a 132kV generation connection where loadings of 300% line rating could occur – possibly impacting on 200,000+ customers, a ranking of 2 (above under-frequency load shedding) may be applicable. In contrast an 11kV connection with a worst case of say, 110% line rating, may be more suited to a ranking of 6 (above 11kV auto-reclose). The technical requirements for each scheme would clearly be different. To correspond to the ranking, protection equipment is always subject to a far more onerous testing and acceptance regime to that of indication / control equipment. It is critical that when a fault occurs action is taken rapidly to prevent damage to plant, and subsequent injury to personnel. However if a control message becomes corrupt, it will generally wait and be re-sent at the next available opportunity. Contrast both of these to the lowly desktop PC, where system failures are commonplace, criticality is arguably lower and problems can often be resolved with a simple reboot of the machine. It is essential to state that these systems are very different in terms of both design and application, a factor dependent on the consequence of failure of that equipment, some of the key differences are indicated in Table B3.

Table B3: Comparison between Protection, Control and Desktop Equipment

Protection Relay SCADA System Desktop PC • Rigorous testing and

proven design to ensure survival and operation in the most harsh conditions and environments.

• Individual components and complete unit tested against: Mechanical (shock, bump, vibration), Environmental (temperature, humidity), Electrical (fast transients, power supply spikes) and RFI (interference from mobile telephones, etc).

• Details of how the protection software

• Standard software blocks are available, but generally assembled to meet the specific needs of the DNO.

• Components (RTUs, etc) tested against mechanical, environmental and RFI effects.

• Some plug-and-play Windows based product design.

• Software designed via a thorough process of specification, design, build and testing, with ongoing consultation and approval between supplier and customer (DNO).

• Standard packages bought ‘off the shelf’.

• Although Hardware and Software are generally tested, there is no rigorous system testing (eg each combination and permutation of software / hardware are not accounted for).

• Plug-and-play technology.

- B14 -

and associated communications are constructed are analysed in detail. A number of typical configurations are thoroughly functionally tested to ensure exact, repeatable operation.

• Testing and approval carried out via a UK wide DNO / Manufacturer ‘Approvals Panel’, in accordance with EATS 48-5 (Issue 2: 2000) [3]

Whilst systems such as AVC have a lower priority to protection relays, they were traditionally designed and built by the ‘protection’ manufacturers, hence, it was natural for them to be tested to the same standards and with the same degree of rigour.

- C1 -

APPENDIX C – COMMON THEMES FOR THE IMPLEMENTATION OF SCADA ACTIVE MANAGEMENT

C.1 Centralised Vs Distributed Logical Switching Schemes

C.1.1 Overview If network control becomes more dependent on SCADA systems, the amount / type of data and methods used to transmit from remote substation back to a centralised control room may need to be reviewed. Increasing the length of any communications channel will result in an increase in the risk of faults along that circuit. Hence, if active management is to rely on communications, it may be best located at a strategic Primary or Grid substation, rather than back in the DNOs control room.

C.1.2 Methods Modern DNO SCADA systems may contain facilities to implement sequence-switching schemes for new schemes on an electrical network via appropriately sited RTUs or central SCADA systems. These systems usually contain logic capabilities to start, stop and create multiple paths within sequences based on network data, usually programmable from a stand alone PC. Schemes can either be implemented within a single RTU or over multiple RTUs in the case of a data concentrator, it is noted that the existing SCADA software architecture will generally cope with multiple sequences running in parallel. The central SCADA system is usually closely coupled with a Distribution Management System that contains a network model and asset database of the 133/33/11kV network. Modern SCADA systems may have some simple sequence switching functionality built into them. There is generally no constraint as to the groups of RTUs where the schemes can be implemented (this is the case with a data concentrator RTU). To implement schemes across a number of substations, it is not possible to use the sequence capability built into a single RTU as there needs to be a co-ordinating entity. This co-ordinating entity could be either a data concentrator RTU, the central SCADA system or a number of small SCADA systems physically located near to the network to which the DG sources would be connected. The pros and cons of using a central SCADA system as against distributed SCADA systems are considered below.

- C2 -

C.1.3 Central SCADA Implementation There are certain functions that must be controlled centrally (eg rota load shedding sequences, global voltage reduction, etc). The key problem associated with this method of implementation is the provision of a suitable reliable communications infrastructure between the central SCADA site and the substations where it will be necessary to control the network. If these are main Primary (33/11kV) substations there is likely to be an RTU in place. If they are small Secondary (11kV/LV) substations no RTU will be in place and more importantly there will be no communications infrastructure in place to the substation. Response times between SCADA / system and RTU will therefore be slow (several seconds) for detection of switch changes. Pros • The centralised SCADA system with sequence capability may already in place. • The centralised SCADA system will contain the network diagram and asset

database, which could provide the basis of intelligence to be built into the sequences.

• Maintenance facilities for hardware, software and database are already in place. • Configuration control of software and data (sequences) is centrally managed. Cons • Some of the older DNO SCADA systems may not have a sequence control

capability or the computing capability to undertake this task, so new SCADA systems may be required.

• A suitably reliable and available communications infrastructure may be necessary.

• Response times for the detection of switch changes may be too slow. This may prevent sequences being carried out in the required time, however, this is application dependent.

• Testing may be difficult because of the physical distances involved. • Complex central bespoke logic, which may require extensive testing and change

management systems. • Risk of single point of failure (ie it all falls over together!). • Response times limited by communications network.

- C3 -

C.1.4 Distributed SCADA System A distributed SCADA solution would comprise small SCADA systems being located in a substation local to the distributed generation. A number of ‘small’ RTUs would be located appropriately in the substations in the scheme. It would be necessary to install a communications infrastructure. The design of these systems would have to reflect the required mean time before failure / availability criteria. It may be advantageous if a single facility existed for the management and generation of the sequence schemes, which could be distributed manually or via a dedicated support / monitoring workstation. In some cases this could be the central SCADA system. Some means of remote health monitoring of the system would be necessary. Pros • If simple, modular and repeatable logic can be applied then the capital

expenditure may be cost effective. • The communications infrastructure could be provided by a low cost exception

reporting radio system (although this is application dependent. It would generally be unsuitable for continuous monitoring or Primary-to-Primary sites – the distances between which may be great).

• Subject to application, the response times / performance requirements could be met.

• May be possible to create simple modular approach to logic. Cons • It may be incompatible with the central SCADA system. • Additional maintenance facilities and skills (DNO and third party) may be

necessary for hardware and software. • Multiple distributed SCADA systems could be difficult to arrange unless some

management tool was put in place together with a communication path. • It may require field visits for logic modification. • Additional field staff may be required. • Solution may be less ‘asset effective’ than, say a hard-wired intertripping

scheme, for thermal overloads – this would be dependent on the complexity and repeatability of a SCADA solution.

• Response times limited by communications network. It is application dependant as to which technology would be the most suitable and cost effective as these are currently in their infancy and there are no simple rules or repeatable logic that can be applied globally.

- C4 -

C.2 Generic Advancements

C.2.1 SCADA Availability on Network (Switchgear) Embedded Reinforcement Figure B2 indicates the extent of substations with SCADA capability on the existing electricity network. So whilst most of the higher voltage networks (132kV, 33kV) have full SCADA control, this becomes more limited as the voltage levels reduce. At 11kV, many of the limitations lie in not only the provision of RTUs (eg for 11/0.433kV substations), but also the physical capabilities of the older types of switchgear (eg manual close, etc).

C.2.2 Communication Channels Reliability As the age profile of the public/private communications systems increase, so the reliability of these channels decrease. As the dependence on communications increase with the network becoming more active, the quality and reliability of the infrastructure must improve accordingly. Whilst diversity and redundancy can be built into systems to improve reliability, restrictions in the number of available suppliers of communications networks (especially in rural areas) leads to limited and often costly options for the DNO. Capability The Private Wire (PW) analogue lines commonly used in the UK consist of a twisted pair cable with bandwidth capabilities of the order 300 to 3100Hz. By comparison, analogue coaxial cable possesses bandwidth capabilities in the 10s of MHz range and digital fibre optics in the order of 10s of THz. It can be seen in terms of bandwidth alone that digital communications offer great advantages over their analogue equivalents. Some other comparisons are shown in Table C1.

Table C1: Comparison between Analogue and Digital Communications

Analogue Digital • Slow and prone to noise • Low power consumption • Conceptually simple • Becoming less available

• Robust to noise and channel impairments (therefore reliable)

• Better matched to channel and message source (efficient)

• Conceptually complex • More expensive

Diversity Anecdotal evidence has highlighted some issues over channel diversity of 3rd party communications. For example, a recent fire in a communications cable tunnel in

- C5 -

Manchester (early 2004) caused widespread loss of telecommunications channels from Derbyshire to Cheshire. The effects were the loss of communications for the circuit protection on 132kV and 33kV circuits as far south as Crewe.

- C6 -

Speed Communication speed varies from one DNO to another due to the vintage of RTUs and their adopted SCADA architecture. In the main, 3kHz (Voice Frequency) private wire lines operating at 2400/1200 baud are used to link together multi-dropped RTUs. There are valid technical reasons why the communications speed cannot be increased beyond this for multi-dropped lines. If the Host machine sees poor data from a downstream RTU (ie lots of errors) it initiates a break in communications then sends a ‘retrain’ tone to pick up that RTU, once established, communications will continue as normal. On a multi-dropped analogue line the modems at the centre and at the target need to re-train each time a new RTU is addressed. The re-training time is 0.5 seconds. There is therefore little point in going over 2400 baud on a multi-dropped line as most of the time becomes absorbed in re-training. Furthermore, even on a point-to-point, ‘clean’ line, the speed of the communications will be dependent not only on the channel but also on RTU limitations. If the analogue line was replaced by a digital one the line speed could be increased however, the maximum speed serial link into most of the installed RTUs is 19200 baud, which may require modem changes for many older RTUs. A 19200 baud line would increase the responsiveness and throughput from the SCADA system to the RTUs (a propagation delay of >1sec from RTU to host is typical for most existing systems, this also being a function of the message length). Digital Communications To overcome bandwidth and speed issues, it may be necessary for the DNOs to increase their use of digital communications. Whilst this may be more straight-forward in town/city centres where 3rd party communications companies have developed their systems to reflect the changing needs of the consumer, it does lead to problems in rural areas. So whilst connection costs in city centres into the fibre ‘broadband’ network are lower, in the sparsely inhabited rural areas (where windfarm generators are likely to be located), costs will be significantly higher. Indeed, it is unlikely that large-scale fibre broadband installation into small villages without exchanges will occur in the foreseeable future. Recent developments in radio broadband may alleviate this problem for the domestic market, and could present possible solutions for rural electrical connections. Alternatively, if the DNO installs its own digital communications network alongside and in conjunction with its electricity circuits, more elaborate control systems could be developed. Many DNOs are now investigating methods to use their existing ‘wires’ networks as a medium for communications with technologies such as Optical Path Ground Wire (OPGW), microwave digital channels, digital communications over copper wires or even Optical Path Phase Conductor (OPPC). There are a number of other recent developments that are presenting communications opportunities in the more rural areas, away from the reaches of optical fibre. GSM (mobile phone technology) is widely available and would be suitable for lower priority applications where the speed or number of dial up(s) is

- C7 -

not a necessity. Another possibility is to utilise satellite communications, clearly, this would get over the issue of geography (hills, estuaries, etc.), but the associated system costs would have to be addressed. The most suitable communications channels for a given voltage level would have to be assessed against a number of factors, including: availability, geography, speed, bandwidth, reliability, impact of failure and above all, the cost of installation. The matrix table below shows a sample of suitable channels and their application at each voltage level. Of course, more detailed studies will be carried out within the DNOs on a site by site basis taking all economical factors into consideration.

3 Unsuitable (typically) 2 Suitable in some

circumstances 1 Suitable (typically)

Table C2: Communication Channel Applications

Channel LV 11kV 33kV 132kV Fibre Optic 3 2 1 1 Copper (digital) Pilot Cable 3 2 1 2 Microwave (digital) 3 2 1 1 Power Line Carrier 3 2 2 2 Copper (analogue)

Pilot Cable 3 2 1 1

Licenced VHF 2 1 1 2 Radio qx(event triggered)

UnLicenced UHF

2 1 3 3

Continuous Radio

Broadband 2 1 1 2

Satellite (one way) 1 1 2 3 Satellite (full-duplex) 2 1 1 1

Mobile Phone (GSM) 1 1 1 2

C.2.3 Remote Terminal Units Inherent Time Delays Digital Consider an exception reporting system utilising digital inputs with an 8 byte poll and a 20 byte reply. Under quiescent conditions, to retrieve digital data polling for one RTU on a 1200 baud line takes about 0.25s. When there have been a number of system changes (analogues and digitals), this may increase to 1.25s. However, now consider the same line but now with 12 multi-dropped RTUs, under quiescent conditions, polling of all RTUs takes a minimum 3s (0.25s x 12 = 3s), but under the non-quiescent conditions, this might extend to a maximum of 15s (1.25s x 12 = 15s).

- C8 -

Min = 0.25secMax = 1.25sec

RTU 1

Host

Min = 3.0secMax = 15.0sec

1200baud line

8 byte poll20 byte reply

RTU 2

RTU 12

12 Multi-dropped RTUs

RTU

Host

1200baud line

8 byte poll20 byte reply

Singular RTU

Figure C6: Graphical Representation of Digital Polling Time Delays

Analogue To minimise the amount of data transmitted, analogues (line currents, busbar voltages, etc.) are filtered, so that a signal will only be sent if it has changed outside a predefined bandwidth, Figure C1. In addition to the filtering, there is an inherent delay built into the system to prevent misinterpreting a ‘glitch’ in the system for a real change on the network. This will lead to issues if the network changes are of short duration.

Anal

ogue

Sig

nal (

p.u.

)

Deadband

Filte

red

Sig

nal (

p.u.

)

1.010

1.005

1.000

0.995

1.010

1.005

1.000

0.995

Time Figure C1: Filtering of Analogue Signals by the RTU prior to Transmission

Due to the polling, there will always be some kind of delay due to the fact that the communications is not permanently ‘open’ (ie it is polled at timed intervals determined by the SCADA architecture). Further to this, the RTU tries to determine whether this change was transient or a genuine increase/reduction. Referring to Figure C2, although the signal when polled can be seen to increase at time t=0+6, the

- C9 -

RTU isn’t sure whether the change was genuine, so it waits until the next pole to verify. At t=0+9 the signal is still high, but to be certain the RTU wants to confirm with one more check. At t=0+12 the RTU is certain that the increase is genuine, and so it sends the information through to the SCADA Host machine. To correct for this time delay, a time tagging of t=0+6 (rather than the actual t=0+12) is sent, this effect is identical for an analogue reduction (at t=0+15). From this simple example, it can be seen that the SCADA analogue network does not operate in ‘real-time’ – in actuality it runs at around real-time +20seconds! Furthermore, there is a secondary effect due to the internal checking, as the SCADA system will not react or transmit short duration spikes or lulls in the analogue signal.

t=0 t=0+3 t=0+6 t=0+9 t=0+12 t=0+15 t=0+18 t=0+21 t=0+24Time (seconds)

FilteredSignal

Signal when poled

TransmittedSignal

Poll 0 Poll 1 2 3 4 5 6 7 8

Figure C2: Time-Delays and Time-Stamping of Analogue Signals (polling interval of

3 secs)

Improvements to RTU Capability Other than replacing the analogue communications channels for digital equivalents, additional factors to be considered for improving the SCADA architecture are: • Reduce the number of RTUs per host / hub machine. • Reduce the number of multi-dropped or re-generated RTUs on a given

telecommunications ‘line’. • Replace all RTUs and all communications in a particular area. Clearly there are cost implications for these solutions (through the installation of more hub machines/communications channels), which would need to be appropriately funded to take place.

- C10 -

Speed The speed requirement of an active management solution will be entirely application dependent. For those solutions where fast communications are necessary, it will be important to consider that often the communications speed for many existing RTUs may be restricted by the operating speed of the modem. As an interim solution, if existing RTUs are maintained, but the number of multi-dropped signals reduced the communications speed from substation to Control Room would improve (there is a limit to the number of RTUs that can be accommodated on one line). Additional RTUs and increased RTU capacity could be coped with in the majority of DNOs without deterioration of the performance of the system. If the number of multi-dropped lines is reduced, there will be a necessity to install (or rent) additional communications channels. Protocol Clearly, it is not possible to install whole new systems and protocols in one step. Therefore, any advancements must work in conjunction with the existing system until a time when the whole system (or a part of the system) is in a position to fully change over. This will mean that unless separate dedicated channels are available, two or more protocols may have to be used over one communications system. Whilst not impossible, it is not preferred to run multiple protocols over one communications channel.

C.2.4 Future Proofing Historically, DNOs have purchased SCADA systems with RTUs that use proprietary interfaces. The SCADA systems and RTUs have been replaced (or expanded in the case of RTUs) at different times. This has preserved these proprietary interfaces. New SCADA systems have been programmed to cope with the existing RTU base and in some cases new RTUs have been programmed to emulate the existing RTUs to avoid changing the SCADA system. RTUs have become more intelligent with the advance of microprocessor technology. Manufacturers have added functionality to them to make them programmable by users. The languages used for this functionality are again proprietary. Many DNO SCADA systems now have functionality to create some simple sequences of instructions to create programs for voltage reductions schemes, load reductions schemes and reconfiguration schemes in substations following a trip. Once again these systems are proprietary. When SCADA/RTU systems are replaced the programs/applications have to be re-coded and tested which incurs significant expense and risk.

- C11 -

Standards Over the last ten years, IEC standards have emerged for RTU protocols and Process Control Languages. Initially the Process Control Languages were aimed at the process industry but it was quickly recognised that these languages were also applicable for the programmable functionality required by RTUs and in some cases SCADA systems. SCADA System to RTU Interface IEC 60870-5-101 and IEC 60870-5-104 are high-level protocols that the IEC has produced to address the links between SCADA systems and RTUs. IEC 60870-5-101 applies to serial communication links whereas IEC 60870-5-104 applies to TCP/IP communication links. The IEEE recommends both of these protocols for communication amongst master (SCADA) stations and RTUs IEC 60870-5-103 has also been produced to interface to Intelligent Electronic Devices (IEDs).

- C12 -

Sequence Control in SCADA Systems and RTUs IEC 61131-3 is a programming language standard that originates from the Programmable Logic Controllers (PLCs) but has been adopted very widely in the industrial world. It provides the solution to the problem of providing an open solution to control and automation. A major benefit to end-users using IEC 61131-3 compliant products will be the possibility of being able to port control system software to different products. Applications developed for one manufacturer’s PLC product family should theoretically be able to run on any other IEC compliant system. This also applies to applications developed for IEC 61103-3 compliant RTUs and SCADA systems. IEC 61131-3 comprises five languages:

• Ladder Diagram • Structured Text • Sequential Function Chart • Function Block Diagram • Instruction list

Products are available to provide PC based graphical tools to program applications in IEC 61131-3 and to provide execution engines on RTUs and Unix/Linux/Windows based SCADA systems. Tools are provided for editing, debugging, code generation, documentation, on-line monitoring, off-line simulation and on-line changes. Although these high level standards are common, the detail in their application are generally not, therefore, it is unlikely that systems designed and built to these standards but developed by different manufacturers will be totally plug-and-play. Summary From the manufacturers point of view, DNOs would clearly benefit from standardising on RTUs, which are IEC 60870-5 compliant although this will be of little benefit in future proofing applications developed for a dynamic active network management system. If however, these applications are developed using the IEC 61131-3 languages they will be platform independent and will be both flexible and re-usable. Applications developed for an RTU based scheme will be re-usable if the strategy changes to a SCADA based scheme and visa versa. When the SCADA/RTU system is replaced, the investment in the applications will be preserved, as they can be easily ported to the new system.

- D1 -

APPENDIX D – PROPOSED SOLUTIONS FOR SCADA ACTIVE MANAGEMENT

D.1 Future SCADA Applications to Accommodate Generation

Any active management solution is likely to incorporate a number of the downstream products mentioned in previous DTI reports* (eg dynamic line rating schemes, fault limiting devices, voltage regulators, etc). Expanding on the solutions highlighted in the Basic Active Management (BAM) reports [9, 10] and investigating some of the features of the UK system leads to a number of potential active management / SCADA applications, which are discussed in the following Appendix. Indications have been made as to how far the technologies for measurement, decision and actioning stages (described in Figure B4) have advanced in terms of the short, medium and long term, together with an indication where it may lie in the overall active management model depicted in Figure 3. It is of note that development timescales indicated have been included as guidance only and are conditional upon whether there is a suitable market and that research is carried out in these areas in the immediate future.

D.2 Potential Loadflow Solutions

D.2.1 Overview The loadflow issue relates to minimising the risk of damage/failure that could occur should a circuit become overloaded. There are two main factors that will have an affect on overload: • the actual ratings the circuits themselves • the amount of power transmitted down the line. If a generator can permanently match its output to a local load, then equilibrium could be achieved, thereby reducing the power exported down a line and maximising the generation in an area.

* Much of the work on Basic Active Management has been done under the TSG: WS3, and is largely available through the DGCG website – www.distributed-generation.gov.uk

- D2 -

D.2.2 Improved Network Thermal Modelling Maximising Circuit Ratings - Background

The ratings of the higher voltage, 33kV / 132kV circuits are generally categorised using two or four ratings (respectively) relating to the time of year, Figure D1. These figures are a simplification of the effect of

ambient temperatures on circuit ratings. A more accurate representation would clearly be a curved profile the inverse of the mean temperature. Where feeder current analogues are not transmitted back on the SCADA system, the lower value, ie summer, is assumed; this is the case for all the LV, the majority of the 11kV and some of the 33kV networks. For most of the 33kV and 132kV networks, winter, summer and possibly spring/autumn ratings may be incorporated into the database of the front-end control software, providing warning alarms to Control Engineers. It is important to note that these warnings are just that, ie alarms to inform a Control Engineer of an overload, and that they are not linked to directly activate a circuit trip. Although the functionality for such warnings are often in place, they are often not fully exploited. Difficulties in maintaining the database following day-to-day circuit modifications (eg fault rectification, where the onus is on restoring supplies, not noting the exact length and type of cable/line used to rectify the fault), generally result in the conservative summer ratings being used throughout the year.

0

2

4

6

8

10

12

14

16

18

JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC

Tem

pera

ture

(°C

)

Circ

uit R

atin

g (A

mps

)

132kV Line with Four Season Ratings

WinterSpring Autumn

Summer

Summer

Winter

500

400

300

200

100

0

33kV Line with Two Season Ratings Figure D1: 132kV and 33kV Circuit Ratings Vs Mean Monthly Average Temperatures

(Temp. Data: England & Wales from 1962 to 2003 – source: UK MET Office)

Implementation Requirements • The simplest method of implementation is to build the functionality into the

SCADA Host machine, so that alarm levels are switched from summer to winter at specific times of year.

- D3 -

• Active cell/unit: Some DNOs employ RTUs with the ability to alter seasonal / time of day circuit ratings. These changes are based on a time stamp (ie they switch over at a specific time of day/year) and are not reliant on external signalling.

• To enable this technique to be utilised across the networks it will be essential to undertake research into the calculation of cable / line ratings at voltages down to LV.

- D4 -

Thermal Modelling One way of further exploiting the ratings of circuits, is to build an accurate thermal model that links the ratings of the plant to the local ambient conditions (solar gain, rain, wind, etc), and then scale them accordingly [11].

Such a solution would smooth out the step changes in ratings and with further development, be particularly useful for overhead line networks, with windfarms increasing their output to take into account the cooling effects of wind across a line. To accurately model this, localised ‘hot-spots’ would have to be identified and monitored using suitable means. Solutions such as the Power Technologies Incorporated (PTI) ThermalRate® System [12] show potential opportunities for increasing the ratings of a line. Whilst marketed as a product for transmission networks, the system could be adapted for use on the distribution system.

Table D1: Development Table for Thermal Modelling

Technical Considerations

Unit Available (Y/N)

Likely Timescales (if

developed) Measurement Thermal modelling tool (out on

network) Y Various

Developed for Transmission

System Decision Logic system to modify line ratings

(located in front end software) N Medium Term

Action Feed to modify alarm limits or signal to generators to ramp down (based on logic in decision unit)

Y (alarms)

N (signals to gens)

Available Now (for alarms)

Medium Term (for signals to

gens) Communications

May need high bandwidth channels if all data is brought back to control room, less onerous if this is not required

N Medium Term

There may be concern in running circuits on their limit, as the post fault contingency, relating the heating of the lines and their increasing sag, would be minimal. This post fault rating is time dependent and consequently, would require some systems to be put in place to grade with any generator constraining method. The limited availability of circuit parameters on the distribution network suggests that it would be the highest voltage (eg 132kV) networks that would be the most suitable to this type of technology*. However it is noted that the measurement units developed for transmission circuits are based solely around the variable ratings of overhead lines. As there are very few overhead line circuits, especially at distribution voltages, wholly devoid of cable sections, it may be these cable sections that are the limiting factor on the overall circuit rating. As the above thermal

* See level of detail given in TGN 26

- D5 -

modelling tool is biased towards overhead systems, further work may be required to make this solution viable for the distribution market. Implementation Requirements • Model the identified lines out on the network • Feed this information back to the SCADA Host • Either update the alarm levels (simplest) or feed back into other constraint

management schemes (more complicated)

- D6 -

D.2.3 Constraint Management Overview Following the work carried out for Engineering Technical Report 124 [13], it has been shown that whilst hard-wired intertripping solutions are acceptable for a single generator, problems soon arise when considering the connection of multiple generators. A SCADA based software solution may give increased flexibility, allowing modifications to constraints and possibly the constraint merit order to be changed on a more fluid basis. With an increased generation penetration, it is highly probable that there will be an increase in the number of constraining signals and that they will have to be used on a more regular basis. Direct Intertripping through SCADA - Principles Most 33kV and many Primary substations have remote control capability through the existing SCADA system. If a logic scheme could be embedded into the SCADA system, trip signals could be transmitted via this route, utilising existing infrastructure Figure D2. The advantages of using a SCADA system over the conventional hard-wired intertrip schemes may be its reduced hard-wiring communications costs and its flexibility. Whilst design rules such as a practical limit for the number of generator intertripping schemes in a network area would still have to be determined (to ensure the logic complexity does not become too unwieldy), a SCADA approach may assist future network/constraint changes. The location of the logic would be dependent on the DNO and the architecture they have adopted – in some cases this may be suited at the central Control Room, in others, it may be advantageous to embed it in a suitably located RTU further into the network.

- D7 -

Load

11kV Busbar

33/11kVPrimary

Substation

Load

RTU2

RTU1

RTU3

SCADALogic

Centre

ControlRoom

33kVSubstation

GeneratorSubstation

Figure D2: Principle of Generator Power Flow Control using SCADA Intertripping

If the network constraint is located at a point remote to that of the generator, some form of communications between the two will be essential. Improvements to the communications network may be necessary, as the safe, effective operation will be a function of the availability of the communications channel, as well as the speed and logic capability of RTUs.

Table D2: Development Table for the Principles of SCADA Intertripping




developed) Measurement Feeder CT analogues (& busbar VT

analogues) sent to SCADA Y Available Now

Decision Logic scheme embedded in RTU(s) / SCADA Hosts, etc

N Short to Medium Term

Action DNO / Generator RTUs and circuit breakers

Y Available Now (for DNO)

Communications

Fast, reliable communications essential

N Medium - Long Term

Existing constraint management schemes concentrate on either tripping the generator, or requesting the generator to reduce output (back-off) followed by a slugged trip signal (ie the generator is tripped if the overload is not removed in a predetermined time). There may be occasions where it would be possible to send some form of signalling to the generator to give them some indication of the available network capacity. In both occasions, it is essential that the tripping signal

- D8 -

be either sent to the DNOs circuit breaker or one under its direct responsibility, to avoid any issues with control boundaries. To this end, for the purposes of SCADA based loadflow constraint management, this report considers: • Generator trip based on power flow measurements • Generator power output control based on power flow measurements These constraining / intertripping methods are discussed in principle, with the technicalities of these are discussed in greater depth in Appendix E. The required robustness built into the design for these solutions would be dependent on: • The amount of overload • The effect this has on an adjacent network It is noted that fail-safes would have to be built into any SCADA system for loss of communications.

- D9 -

Generator Trip Based on Power Flow Measurements Modification / SCADA Input to Traditional Relay Schemes Constraining or tripping of generators based on their output power following single circuit outages is a solution already applied on some UK networks (see

example in Appendix A). Manually programmed overload relays set to the lines summer line rating operate a hard-wired system local to the generator. Backup is also provided locally as the overload relays are fed into a timer circuit, such that if the generator fails to ramp down in the predetermined time the generators export circuit breaker is opened. A simple SCADA modification could be for a changeover scheme to modify circuit ratings at a specified time of year / ambient conditions, Figure D3. This allows the generator to utilise the increased winter capacity, and give benefits to the DNO as its simplicity, using predominantly local control would reduce the risk should the communications fail. The restrictions of such a scheme correspond to the effects of an adjacent generator or load connection. If this occurs, the loadflow down the two feeders would be skewed, and could result in spurious tripping of one of the circuits. Greater flexibility could be built in if the logic in the relays themselves were to be remotely modified.

Line Rating18MVA Summer22MVA Winter

32MVA Generation Capacity

OverloadRelay

OverloadRelay

VariableSettings

11kV

33kV

33kV

33kV33kVRTUwith

LOGIC

ControlRoom

VariableSettings

Line Rating18MVA Summer22MVA Winter

TMTM

Figure D3: Flexible Generator Tripping Based on Power Flow

A further modification to this type of system could be to replace the standard overload relay for a thermal overload relay, similar to those used for motor loads. As a thermal overload relay will take into consideration the heating effects caused by variable load/generation, it will not be as sensitive to spurious or short-lived current

- D10 -

spikes that may occur (eg due to Power Output α Wind Velocity3 relationship of a wind turbine).

- D11 -

Full SCADA Options A full SCADA option would utilise the SCADA infrastructure in the place of protection relays. In the case of the thermal overload relay, it may be necessary to provide an appropriate model in the RTU. SCADA generation trip may be suited to either local or remote I/O if the SCADA communications channels can be utilised. The table below is for the simplified circumstances where all I/O is local. Where this is not the case (ie the overload is detected at a location some distance from the location of the generator) the reader is referred to the Active Cell schemes described in greater depth in Appendix E.

Table D3: Development Table for SCADA based Generator Tripping Schemes (Local I/O)



Likely Timescales (if developed)

Measurement Feeder CT analogues sent to SCADA Y Available Now Decision Logic scheme embedded in RTU and

to be built to give different ratings depending on ambient conditions / time of day / etc Backup may be provided via overload relays

N Short Term

Action Output to generator to be in stages to indicate the degree by how much they must constrain. Backup via generator(s) / DNO circuit breakers

N Short Term (for output constraint)

Backup: Available Now

Communications

Existing communications channels should be adequate

Y Available Now

Implementation Requirements (Local I/O) • RTUs with logic ability • RTUs programmed to run logical sequences based on generation output, circuit

loading and circuit breaker status • Warning alarms sent from RTU to generators interface, with slugged tripping

signal • Backup tripping direct to DNO / generator interface circuit breaker

- D12 -

Generator Power Output Control Based on Power Flow Measurements Whilst there are some constraining schemes based on tripping sections of a generating site for larger capacity schemes, there use is not widespread and is currently quite crude.

A full SCADA controlled constraining scheme would ideally tie in with the local control unit at the generating station to signal to site when to back-off its output. Figure D4 gives a simplification of a scheme implemented in a SCADA environment. The analogue power flow monitoring information is extracted straight from the RTU (2), and sent to an interface controller. The logic centre incorporates a model of the circuit ratings, which are switched depending on the time of year / ambient conditions. From analysing the acquired data and relating that to the network state, control signals can be issued to the RTU (3) at the generators substation to constrain or enable blocks of generation. A full solution may be to utilise a software intertrip, sent via a suitably secure communications channel.

Load

11kV Busbar

33/11kVPrimarySubstation

Load

RTU2

withLOGIC

RTU1

SCADAInterface

ControlRoom

33kVSubstation

DNO / Gen.ConnectionSubstation

I/TBU

Control

RTU3

withLOGIC

GeneratorOwned Asset

Line 1 Line 233kV Line RatingsSummer = 18MVAWinter = 22MVA

Figure D4: SCADA Generator Power Reduction Scheme with SCADA Intertrip Backup

- D13 -

Start

IsMonth04 - 09

LineRatings =18MVA

LineRatings =22MVA

Measure Currentin Lines 1+2

Is Current>120%Rating



Signal toTrip Gen CB

ResetTimer

Reduce Genby 1MVA

Enable Genby 1MVA

Full Enableto Gen

InitiateTimer

Delay

Time Out

120%

100%

80%

0%Constrained Ramp Up

Initiate Reduction

RemoveConstraint

If rapidramp up

TripGen

Time

Line

Cur

rent

Y

N

Y

Y Y

N N N

Figure D5: Example Enable/Constrain Signals for the above Case Study (line backup protection set at 140% line rating)

Table D4: Development Table for Generator Power Reduction through SCADA




developed) Measurement Feeder CT analogues (& busbar VT

analogues) sent to SCADA Y Available Now

Decision Logic scheme embedded in DNOs RTU or extracting data from a remote site

N Medium Term

Action Variable signal issued to the generator informing them of the degree by which they must constrain. Backup: Circuit breakers

N Medium Term Backup:

Available Now

Communications

Fast, reliable communications necessary, also may require additional bandwidth requirements for I/T signals

N Medium Term

- D14 -

Implementation Requirements (Local I/O) • RTUs with logic ability • RTUs programmed to run logical sequences based on generation output, circuit

loading and circuit breaker status • Enable / Constrain signals sent from RTU to generators interface, with slugged

tripping signal • Backup tripping direct to DNOs generator interface circuit breaker

- D15 -

D.2.4 Load / Generation Forecasting As mentioned previously, if a generator(s) can follow the local load, ie with less power exported through the circuits or causing reverse power through transformers, then it would be theoretically possible to allow more

generation to connect. In order to achieve this, it would be essential that the DNO have a good understanding of the load/generation profile in control timescales (ie day-by-day, hour-by-hour). It is recognised that the UK Transmission model, where generators bid on export over half-hourly periods, is unlikely to come to the distribution system. However, an improvement in knowing when a generator is to export and by what amount, would be useful and may be increasingly necessary for future network control. It is of note that a number of systems are under investigation in Ireland and the US to accurately predict outputs from windfarms based on local weather forecasting, windfarm topology, etc, these can be further improved by linking the modelling to some form of self-learning artificial intelligence. Similar forecasting tools used by the DNO could review the network load, network conditions and expected generation profile to recommend circuit configurations to best suit all parties (see also Holistic Solutions later).

Table D5: Development Table for Load / Generation Forecasting




developed) Measurement Feeder CT analogues sent to SCADA.

Generation patterns / expected load demands and profiles

Y (CT

info.) N

Long Term

Decision Logic centre / network model determining suitable operating regimes and constraints for connected generators

N Long Term

Action Issue constraints to generator controller units

N Medium Term

Communications

Available, reliable communications between generator and DNOs control room

N Medium Term

Implementation Requirements • The requirement for generators to send forecasting information through to a

centralised point within the DNO. • An electronic method of collating this information, cross-referencing to system

outages of other constraints (eg faults) and revising each generator’s network constraint / priority as required (see Optimum Power Flow devices).

• Feedback into embedded constraint management systems.

- D16 -

Potential Voltage Profile Solutions

D.2.5 Background The voltage received at the remote end of a circuit is equal to the source voltage and any voltage difference along the feeder due to load or generation, such that:

VVQXRPVE ∆=+≈−

I

V E

R + jX

P

Q

R Line ResistanceX Line ReactanceP Real Power (MW)Q Reactive Power (MVAr)V Sending End VoltageE Receiving End Voltage

Figure D6: Voltage Profile down a Feeder

Traditional techniques for controlling a remote voltage (E) involve adjusting the voltage of the sending end (V) via the DNOs tap changers. This technique is effective for load customers but when a generator connects, changes in the direction of real power can cause the voltage at the remote end to rise.

- D17 -

D.2.6 Existing Load-Shedding Systems Many of the more modern transformer AVC schemes operate in conjunction with load-shedding ‘voltage reduction’ systems. For a purely resistive load, Ohm’s Law states that it is possible to reduce the current by reducing the voltage. This is the principle that is used

by DNOs to reduce the power down feeders at times of high demand/low generation. Some Grid Supply transformers are fitted with 3% voltage reduction capability, with some having two step capabilities (3% and 6%). These features are effectively altering the set point of the AVC (ie 0.97p.u. and 0.94p.u. respectively) and may by used by Control Engineers to fine-tune the network, forcing power down certain feeders. It is noted that on interconnected circuits, the use of load shedding schemes to reduce voltages will force predominantly reactive power down a feeder (not much real power), due to the network X/R ratio (typically X = 3, R = 1). Hence ∆V = P + 3Q, so for a change in V, three times as much Q flows as P.

Table D6: Development Table for Voltage Control via Load Shedding Schemes




developed) Measurement VT analogues sent to AVC Y Available Now Decision Voltage Reduction Unit modifying

Automatic Voltage Control set point by 3% or 6%

Y Available Now

Action Transformer Tap Changer, tapping up or down as a reaction to changes in set point

Y Available Now

Communications

Standard communication channels are acceptable

Y Available Now

Implementation Requirements • AVCs with load shedding capability • Remote initiation through DNOs SCADA system

- D18 -

D.2.7 Remote Change of Transformer AVC Setpoint As described above, transformer load shedding schemes effectively alter the setpoint of the transformer AVC system, typically either 3% or 6% below nominal. The logical progression for AVC scheme control is to

give the DNOs Control Engineer the facility to alter the AVC setpoint remotely across a wider range (±10% in steps of 0.5%) to better control voltages or minimise VAr flow across a number of transformers.

Table D7: Development Table for the Remote Change of AVC Setpoint




developed) Measurement VT analogues sent through SCADA Y Available Now Decision The DNOs Control Engineer Y Existing Action Decision Unit feed into AVC relay to

modify set-point (which in turn causes the transformer tap changer to react)

Y Short Term

Communications

Existing communications channels should suffice.

Y ‘Reasonable’ communications

available The first stage of an ‘Actioning’ unit will be available from VA Tech / Fundamentals in 2003/2004, allowing the set-point of the AVC relay to be modified from a remote location (eg control room).

- D19 -

D.2.8 Automatic Network / Generator Voltage Control Trials are currently in place for an Active Cell concept in the DTI project on ‘Active Local Distribution Network Management for Embedded Generation’ using Econnect’s GenAVCTM device. This study [14] (to finish in 2005) looks at two generations of the GenAVCTM:

• 1st: Controls a single voltage control device at the 33/11kV substation to which the DG is connected.

• 2nd: Dispatches DG and schedules control devices including voltage control devices, circuit breakers and reactive power compensators.

Initial studies on this scheme suggest that the amount of generation exporting down a feeder could be increased by a factor of two.

Table D8: Development Table for Automatic Network / Generator Voltage Control




developed) Measurement VT analogues sent through SCADA Y Available Now Decision A network model and simulator

looking at a portion of the network and determining appropriate settings for transformer tap changers to maintain system voltages within Statutory limits

N Medium Term

Action Decision Unit feed into AVC relay to modify set-point (which in turn causes the transformer tap changer to react)

Y Short Term

Communications

Existing communications channels should suffice for the first generation. Added bandwidth may be required for the future.

Y ‘Reasonable’ communications

available

As above, the first stage of an ‘Actioning’ unit will be available from VA Tech / Fundamentals in 2003/2004, allowing the set-point of the AVC relay to be modified from a remote location (eg control room). Implementation Requirements • SCADA Host or Distributed on Micro-Host • Existing communications should be sufficient (high bandwidth not a requirement • Set up AVCs with some form of limits (eg 0.9 – 1.1 p.u.)

- D20 -

D.3 Potential Fault Level Solutions

D.3.1 Overview As previously stated, existing networks are designed such that switchgear fault levels are kept below their rating. The fault power, implications of failure and restrictions imposed under the Health & Safety at Work Act (1974) naturally lead to the cautious attitude to fault level. The principle argument is one of ‘fail safe’, and it is generally agreed that in its current form, SCADA solutions do not possess the speed of operation or 100% reliability required for clearing faults. The issue of ‘sequential switching’ highlighted in the Basic Active Management (BAM) report [9] is currently under tender for investigation in the 2004 round of DTI projects to determine whether the risks are acceptable and compliant with current Legislation and Regulations. Whilst this is beyond the scope of this report, there are a number of solutions that could be developed as a pre-fault contingency, ie used to reconfigure the network prior to a fault and depending on the generators connected, to a state where fault levels are considered ‘safe’. As the penetration of DG increases, fault level becomes more problematic, due to the inherent trade off between generation connection and a rise in fault level. This raises fundamental problems on the lower voltage networks, which SCADA based active management alone will not address. Indeed, this may often be the trigger to connection at higher network voltages.

- D21 -

D.3.2 Network Reconfiguration Overview One solution to limit fault levels for generation connection is to reconfigure the network, by opening network split points (or splitting up interconnected

networks). This increases the source impedance to the generator, but by doing so, may reduce the quality of supply to customers, through increasing the affect of voltage dips or harmonic distortion. This impact would clearly have to be assessed on a case-by-case basis, as it would be unacceptable to significantly worsen supply quality to existing customers. Furthermore, there is a risk of subjecting additional customers to a loss of supply in the event of a network fault, which would incur CI / CML penalties. The more open points on the network, the less secure the system becomes. A number of SCADA designed ‘auto-close’ schemes are already being implemented for supply reconnection purposes. The logic can sit in either the centralised SCADA software or within suitable RTU logic and can be applied to various voltage levels taking initiation from a number of ‘trigger points’, which subject to approval by the control engineer, could then fire through a logical sequence to modify the network. Fault Level Monitoring Software Fault level monitoring in this context is a software-modelling tool to better determine the actual fault level on the system at a given time, not only in terms of source impedance, but also taking into account motor / generator infeed. There are a number of solutions under development to determine this based on small scale disturbances caused to the network when transformers change tap or circuit breakers open. Accurate knowledge of true fault levels will enable the electricity network to be designed and operated closer to the design fault level ratings, perhaps enabling further increases in generation connection. Constraints for this type of system will be based on the timescales taken to build up a library of reliable data. To be accurate enough, the model has to include a whole host of network combinations and permutations, from the network configuration to different load / generation demands through to individual transformer tap positions! Network trials into this area, show the expected results that the longer the device is left on a system, the smaller the error in the calculation – current analysis suggests a period of 2-3months will generally produce fault levels with an error ≈ ±10%. Whilst useful for improving the accuracy of network design models, they are clearly to slow for consideration in the control timeframe. A DTI supported R&D project to develop a Mark II Fault Level Monitor and improved software is currently under consideration. Given the density of electricity networks in countries like the UK, it is clear that once fully proven, this would be a useful tool.

- D22 -

Table D9: Development Table for Managing Fault Levels through Network Reconfiguration




developed) Measurement Accurate state estimator, assessing

the network fault level in real-time – full visibility of every (large) connected generator / motor required at all times

N Medium Term

Decision Network model assessing the most efficient system configuration to limit fault level and provide the most suitable connection for load customers (in terms of fault restoration and harmonics)

N Long Term

Action Open / Close DNO / generator(s) circuit breakers

Y Available Now

Communications

Reliable communications channels will be necessary

N Medium Term

Implementation Requirements • SCADA Host based. • Reliable communications would be essential. • Fail-safes must be built into system for loss of communications. Active Fault Level Management True ‘Active Fault Level Management’ as discussed in the ETSU ‘Solutions for the Connection and Operation of Distributed Generation’ report [10] suggests that this is the wide-area scheme incorporating a number of the point of connection and local area control solutions (Is Limiters, etc). Whilst it is probable that the control and indication for such a package would be built into SCADA software, until it is agreed which solutions the industry will adopt, it is difficult to determine a suitable programming / SCADA infrastructure.

- D23 -

D.4 Holistic Solutions – Network Optimisation Software

The use of optimisation programmes is becoming increasingly popular on transmission networks throughout the world. These software Optimal Power Flow (OPF) systems are used to model the network and

determine the best configuration to achieve an end result (typically loadflow) by recommending the adjustment of devices such as phase-shifters (quadrature boosters), etc. As they take dynamic information from the live network, they can be used in design and control timeframes, to produce a series of recommendations that can be utilised by network planning and control engineers alike. Each parameter in the software is attributed with a ‘cost’, essentially a weighting factor that dictates its importance. Once calculated, the recommendations are displayed to the user. As these systems are currently operated in an open loop form, the engineer has the opportunity to vet the output from the OPF prior to implementing its recommendations. OPFs offer the decision phase of a truly holistic active network management system, offering an optimal network solution that can be used across any number of scenarios. For example, the OPF software developed by IPSA Power [17] can be developed to fit solutions such as:

• Load management • VAr flow reduction • Optimising generation in the presence of Voltage limits (modifying

AVC setpoints) • Continuous fault level calculation • Active network (n-1) contingency analysis, etc

If the outputs could be displayed in the context of recommended generation outputs – thereby optimising generation for any given network configuration and load profile, then the system could be used to actively manage DG. The final stage of OPF development would be to close the loop so that the optimiser not only took information from the live network, but it also sent automated control signals back through the SCADA system to ‘tweak’ the network or apply / lift constraints within a range of defined parameters. This is not foreseen to be a simple task, and would likely require modifications to the DNOs communications infrastructure.

- D24 -

Table D10: Development Table for use of OPF Software




developed) Measurement Information linked through to SCADA

Host databases Y Available Now

Decision Optimum Power Flow (IPSA Power software - currently in final stages of development).

N Immediate to Short Term

Action Actions sent back though the SCADA system down to remote RTUs.

N Short Term

Communications

Fast, Reliable communications likely to be ‘sticking’ point.

N Medium Term

- E1 -

APPENDIX E – TECHNICALLY POSSIBLE SCADA ACTIVE UNIT, CELL AND NETWORK PROPOSALS

The following Appendix was developed in conjunction with our project partners Thales-IS using, where applicable, the principles of Active Unit, Cell and Network to facilitate the use of distributed logic, thereby assisting in reducing the reliance on communications channels.

E.1 SCADA ‘Active Unit’ Solutions (Local Logic)

E.1.1 Introduction Local logic could be located at the DNO’s generation interface circuit breaker(s). This is the most basic solution, providing the least in the way of facilities to the generator or the DNO. Associated with it are stages of sophistication: • Dedicated hard-wired local logic • A local RTU implementing local logic At the most basic level, local logic sends on/off digital signals to the generator indicating whether export is permitted or not, or to request maximum generation for network support (eg voltage, etc). If the generator fails to respond to a restriction signal, the logic can be configured to initiate a timer and, after a delay, trip the main circuit breaker(s). As with the further systems discussed, local logic faces the fundamental problems of accessing the digital and analogue data, needed to make decisions, from remote substation locations.

E.1.2 Dedicated Hard-Wired Logic Pure hard-wired logic would generally have insufficient functionality to be able to access analogue data from the RTU or SCADA source where communications protocol handling is necessary. Instead it tends to be confined to using continuous signals, measured with CTs at source and conveyed over fibre or copper pilots to the logic processor. These may or may not be available, and the cost of provision, where they are not, may be significant. Hard-wired logic becomes increasingly problematic when multiple generators need to be considered. In these cases, decisions may need to be made as to who is restricted first, and there is little scope for allowing generation sharing. Voltage support requests present similar challenges. Ad-hoc local logic provided to solve the initial problems for one or two generators may get out of hand as further generators are added affecting existing generator’s operating regime.

- E2 -

E.1.3 Local RTU To get over some of the problems of hard-wired logic, a RTU co-located with the DNO’s generator interface circuit breaker(s) may offer greater flexibility. Newer RTUs may be constructed with logical programming capabilities, this allows information that is taken from a local substation to be put through a logic sequence and an appropriate output issued. This may be configured to use the same continuous signals as the hard-wired ‘local’ logic (using the same pilot cabling), or it may act as a ‘master’, with the ability to poll remote dedicated or shared ‘slave’ RTUs.

SCADAInput

Tim er

CTs & VTs

Logic

(AND / OR etc)CTs & VTs Detec tion of

abnormal sta te

Circuit Breaker/Isolator Sta tus

Detec tion ofabnormal sta te

GD NO

CB

Customer

CB

Ability toArm / Disable

‘OP EN’

‘Trip G enerato r’

‘Start/Res et’

‘OP EN’

Local Selec tor/SCADAOutput

A ny s ignal path may be implementedvia a communication channel p rov idedit is superv ised and trips the generato ron failure.

Detec tion ofabnormal sta te

‘System Failure’

OR

Figure E1: Local Logic Unit

To what extent a local RTU is viable, depends on the complexity of the logic required and the extent to which this departs from the RTU’s standard sequencing capability. As the active unit is a locally controlled autonomous system, its functionality does not depend on communications links from remote locations.

- E3 -

Performance Measures may be needed to optimise RTU data access from any remote dedicated or shared ‘slave’ RTUs; this is discussed in more detail later. Overall performance of the Local RTU will also be influenced by any simultaneous access for data gathering by the remote SCADA system.

• CB and other digital change of state detection might be possible at the RTUs internal generators control software interface within 2 seconds, whilst response to these in the form of a digital control output may take a further 1 second.

• Because retrieval of analogue data tends to be slow, typically 5 seconds

between scans, and 10 seconds to confirm a significant analogue change, local conversion to single bit digital may be needed; this is discussed in more detail later.

• Some of these delays could be overcome by bespoke special software within

the RTU giving priority to the generators control functions. Equipment Requirements If necessary, higher speed RTU communications with a Central SCADA System may be required, if this is the case, a kilostream link may also have to be included. • Suitably equipped RTU in an enclosure at a generation site • Bespoke RTU / generator control software development (one-off for each

manufacturer of RTU used by the DNO) • Central SCADA System RTU software download facilities

- E4 -

E.2 SCADA Active Cell Solutions

E.2.1 Introduction This solution, shown in Figure E2, describes a modular Generation Connection SCADA System (GCSS), located at the DNO’s generator interface circuit breaker(s). Such a system could have a fair degree of autonomy, with an alarm and trip capability associated with the circuit breaker and outputs to control factors such as seasonal line settings.

Generation Control SCADASystem(GCSS)

Generator

CB state,trip/close,summer/

winter max.kA select

Comms to Centralor Substation

SCADA Systemh/wwatchdog

main circuitbreaker

alarm ortrip

to access adjacentsubstation ornetwork CB

states, load-flows,tap-changer set-

points

NetworkConnection

generationrestriction &

voltagesupport

messages

Local Analogues(A, kV, MW, MVAr)

Figure E2: Generation Control SCADA System (GCSS)

The GCSS could have a range of generation control algorithmic modules to calculate maximum permissible load-flow, or voltage support requirements, together with standard message modules to provide command messages to the generator. Achieved over a suitably isolated serial connection, the request for generation restriction could be given in quantitative terms, or a request maximum generation for voltage support, advance warning could be given for imminent requests of this type. To monitor the communications, a particular feature of the GCSS would be external watchdog hardware. If this were not addressed from the GCSS within a predetermined time (say 500ms), the watchdog would raise an alarm and initiate a timer either linked to a more constrained output, or to a generator trip. The GCSS itself could also be capable of directly triggering the watchdog eg if it lost vital communications or detected that the generator was not responding to a generation restriction.

- E5 -

Within this solution there are again a number of possible stages of sophistication, particularly with respect to gathering remote digital and analogue data.

E.2.2 Signals from Local CTs The most basic method is for a GCSS to make use of the same continuous signals provided from the CTs that would have been used for local hard-wired logic, however this leads to the same inherent problems of future modification should an additional generator wish to connect.

E.2.3 Dedicated GCSS RTUs The next level of sophistication may involve a GCSS polling one or a number of dedicated ‘slave’ RTUs or RTUs shared with other systems. These RTUs could be pole-top, or conventional, using the most appropriate communications channel depending on distances and circumstances.

Generation Control SCADASystem(GCSS)

Dedicated RTU Interface

Generator

CB state,trip/close,summer/

winter max.kA select

Comms to Centralor Substation

SCADA System

Slave RTU 1

Slave RTU poll

h/wwatchdog

main circuitbreaker

alarm ortrip

to access adjacentsubstation ornetwork CB

states, load-flows,tap-changer set-

points

generationrestriction &

voltagesupport

messages

Slave RTU 2

Slave RTU n

Local Analogues(A, kV, MW, MVAr)

NetworkConnection

Figure E3: A Generation Control SCADA System (GCSS) with Dedicated RTUs

- E6 -

E.2.4 Central and Substation SCADA System Communications and Real-Time Databases

The final level of sophistication and most flexible solution would be to provide a GCSS with hardware and software communications modules able to talk with the DNO’s dedicated SCADA system. As discussed in the following pages, the GCSS could then communicate with any available upstream Central (Figure E4) or Substation (Figure E5) SCADA Systems, reaching into these to access the relevant ‘real-time’ database data these maintained. The objective would be to minimise the need for dedicated RTUs to monitor signals needed by the GCSS for its control duties ie the circuit breaker states, load flows, voltages, tap-changer set points and so on, associated with adjacent substations and parts of the network. In order to accurately control a ‘cell’ of network, the reliability of the communications between neighbouring sites becomes paramount. For more sensitive sections of network, it may be necessary to utilise two diverse communications routes to ensure correct operation – which will of course have significant cost implications.

RTU

RTU

RTU

RTU

RTU RTU

RTU

RTURTU

132/33kV s/stn

Modem RTU

RTU

RTU

RTU

RTU

132/33kV s/stn

Mod

em

RTU

RTU

RTU

RTU

RTU

RTU RTU

RTU

RTURTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU

RTU RTU

RTU

RTURTU

132/33kV s/stn

Modem RTU

RTU

RTU

RTU

RTU


SCADA Sub-System

NMS Sub-System

GCSS Port Real-timedatabase

SCADA Host

Commsto GCSS




GCSSwith Logic

Active Cell

Figure E4: Interface between SCADA Host and GCSS (RTUs in green identify key data points)

- E7 -

As outlined in Appendix B, whilst the existing data concentrator RTUs at the 132/33kV substations act as a master unit collecting information from slave RTUs further into the network, in this form they have no capability for extracting this data and hence using it in logical sequences. This indicates that logic over a number of sites will only be possible via a true SCADA Host machine. To implement an Active Cell in a true distributed environment, it may be possible to replace the data concentrators and RTUs at 132kV level for a system that will act as ‘master’ and be able to read in and use information from downstream RTUs. The new breeds of RTUs and Substation Control Systems (SCS) as being developed for some 132/33kV sites may have micro-host type facilities. It may be possible to develop these for an Active Control purpose in the future, providing that a number of practical issues are addressed, including: • The complexity of the logic or SCADA database • The provision of standard ‘modular’ constraints • A suitably robust testing regime • Decisions as to whether the logic is downloadable or whether it requires a visit to

site by field staff

SCADA NetworkRTU

RTU

RTU

RTU

RTU

RTU RTU

RTU

RTURTU

RTU

RTU

RTU

RTU


SCADA Sub-System

NMS Sub-System

SCADA Host

Commsto GCSS


ModemInte

rface

Por

t




GCSSwith Logic Active Cell

Real-timedatabase

Figure E5: Interface between Micro Host and GCSS (RTUs in green indicate key data

points)

Implementation To facilitate the above, either a Central or a Substation SCADA Systems could be equipped with standard ports able to receive communications conveying requests for data of this type from GCSSs. This would necessitate the DNO to specify the provision of such ports from the Central or Substation SCADA System suppliers.

- E8 -

Ideally, the ports would meet one of existing or emergent standards, such as:

• Common Information Model (CIM IEC 61970-301) • Inter-Control Centre Communications Protocol (ICCP IEC 870-6-503) this

encompasses the Telecontrol Application Service Element (TASE2). • ELCOM 90

The port could provide a standard interface to real-time SCADA data on the Central or Substation SCADA System, irrespective of the type of RTU and/or communications configuration that the system used to collect the data. Central or Substation SCADA System parametric control of GCSSs would also be possible. This would be necessary to co-ordinate the generation from multiple generators having different contracts and rights eg which generator trips first. This would probably necessitate the GCSS being able to write generator status data to the Central SCADA System to enable this to co-ordinate operations. The Central SCADA System would also have to have access to the same analogue, digital and control signals / information from the GCSS, as from any standard existing network RTU. This arrangement could give the GCSS supplier-independent facilities, providing some element of future proofing, ie if the DNO replaced the Central or Substation SCADA System it would not necessitate replacement or modification of the GCSSs. Improving RTU Response & Flagging Communications Loss In practice, it is envisaged that the number of signals required by a GCSS would be small, but optimal response would be necessary. The biggest delays would be associated with the polling of RTUs in the ‘main’ SCADA network with other communications times being rather less. Considering digital inputs, with an 8-byte poll and a 20-byte reply to retrieve digital data, polling one RTU on a 1200baud line takes about 0.25 seconds. With 12 RTUs multidropped from the line, under quiescent conditions, polling of all RTUs takes about 3 seconds. However, under the non-quiescent conditions following a trip, this might extend to 15 seconds worst case to report a digital change of state. With analogue inputs, a further delay must be added due to the RTUs internal scanning of these, typically every 5 seconds. Two successive internal scans may be required before the RTU reports an out of limits value, which may therefore add a further 10 seconds, giving 25 seconds worst case to report an analogue change of state. A number of steps would need to be taken to improve these figures for the small proportion of RTUs retrieving generation control signals. These might include: • Modifications to existing SCADA architecture through faster and/or dedicated

communication lines (Figure E6) • More modern higher performance RTUs

- E9 -

• Local conversion of critical analogues to more quickly retrieved single bit digitals, for example by adding an electronic relay to the CT operating at the desired plant ratings

Some systems are able to use a ‘quality’ of data flag associated with retrieved values, to indicate an RTU input failure. This information would be needed by a GCSS. If this were not directly available, the GCSS would need to assess the status of the RTU as part of the real-time database access.

132/33kV s/stn

Mod

em

RTU

RTU

RTU

RTU

RTU

RTU RTU

RTU

RTURTU

RTU

RTU

RTU

RTU

PSTN Lines

To Host Machine

RTU Information required from these location(s)

132/33kV s/stn

Mod

em

RTU

RTU

RTU

RTU

RTU

RTU RTU

RTU

RTURTU

RTU

RTU

RTU

RTU

PSTN Lines

To Host Machine

Existing Architecture Modified Architecture

Figure E6: Change from Multi-dropped to Dedicated Comms into Key Sites

A Semi-Local Generation Connection SCADA System This is similar to the above solution - except that the GCSS logic is located in a Mini-Host at a BSP/GSP substation rather than associated with the generators main circuit breaker(s), Figure E7. A GCSS located here could potentially control a number of generators, but each generator would require an RTU and suitably fast communications back to the substation to permit remote control of its circuit breaker(s) and load management system. The substation may or may not have an existing SCADA infrastructure. A variant of this solution would be to mount GCSS software on an existing Substation SCADA System.

- E10 -

RTU

RTU

RTU

RTU

RTU

RTU RTU

RTU

RTURTU

RTU

RTU

RTU

RTU


SCADA Sub-System

NMS Sub-System

SCADA Host


ModemInte

rface

Por

t

Control & Constraint/ Enable Signaling


Generator RTU

Log

icSCADA Network

Commsto GCSS

Active Cell

Real-timedatabase

Figure E7: Substation Control System with Embedded Logic

It may be possible to group a number of Micro-Host machines together, sharing information across an IP (Internet Protocol) link in the same way as the Main and Standby Host machines operate. This would allow large quantities of data to be transferred quickly between remote parts of the system, but may require diverse communications, routed via two or more paths (expensive). The expanding use of IP throughout the DNO’s SCADA network may introduce further risks in terms of IT system security. The current SCADA systems employs secure SCADA specific protocols, with point-to-point communications over predominantly privately owned copper channels, which forms an almost islanded network that is difficult to infiltrate from outside. If however, IP were to be used across the public network, it may be difficult to install and maintain adequate firewalls to keep viruses or hackers out.

- E11 -

E.2.5 Centrally Based Active Cell Solutions Central System with ‘Bolt-On’ GCSS With this solution, the GCSS could co-located with the Central SCADA Host System, accessing the same real-time database data as before, but via local communications eg Ethernet.


SCADA Sub-System

NMS Sub-System

GeneratorSCADAControl

SCADA Host

Commsto GCSS

GenRTU

SCADA Network

Real-timedatabase

Figure E8: Centrally Located ‘Bolt-on’ Generation Control

The generator’s systems could be controlled via the Central SCADA System. Each generator would require an RTU to permit remote control of its circuit breaker(s) and protection system. In this respect, it may be essential to maintain a suitable audit trail of controls issued by the GCSS. Alternatively, generator’s RTUs could be controlled directly via the GCSS. Integrated Central SCADA System Based GCSS The final solution is to develop GCSS software and place it on the Central SCADA Host machine. As with the above solution, each generator would require an RTU and sufficiently robust communications to permit remote control of the DNO’s generator interface circuit breaker(s) and constraint management system.

- E12 -

Modification toSCADA Host

SCADA Sub-System

NMS Sub-System

GeneratorSCADAControl

SCADA Host

Commsto GCSS

GenRTU

SCADA Network

Real-timedatabase

Figure E9: Generation Control System Integrated into Main SCADA Host

E.3 SCADA Active Network Architecture

E.3.1 Overview The development of an active network would most likely link into a number of active cells, performing alterations to optimise the running of the network as a total entity. To this end, it is highly probable that some form of software Network Optimiser would be utilised to determine the most efficient network setup and automatically feed this information back out to key sites (ie modifying the settings held in each Active Cell). It is envisaged that these signals would not need to be fast, as there would be an inherent fail-safe functionality with each active cell configured to work autonomously (albeit in a less efficient manner). An example of an overall Active Network model is described in Figure 10.

- E13 -

132/33kV s/stnMicro Host I

RTU

RTU

LogicRTU

RTU

RTU RTU

RTU

LogicRTU

RTU

RTU

RTU

LogicRTU

RTU

Main ControlRoom

Host I

Standby ControlRoom

High Speed IP Link


Host II

132/33kV s/stnMicro Host II

RTU

RTU

RTU

RTU

RTU RTU

RTU

LogicRTU

RTU

LogicRTU

LogicRTU

RTU

RTU

Possible High Speed Comms Links

NetworkOptimiser

Unit Unit

Unit

Unit

Unit Unit

CellCell

Active Network


Figure E10: Active Network SCADA Model

Further details of the Network Optimiser developed by IPSA Power are described in Section E.3.2, below.

- E14 -

E.3.2 SCADA Voltage Control Solutions Introduction As discussed in Appendix A, voltage control is currently achieved from 132kV to 11kV through the use of transformer AVC schemes – an existing active unit. On networks where there is a high ratio of generation to load, voltage and VAr flow problems can arise, which make it difficult in isolation for the AVC schemes to operate efficiently. In order to improve the situation it may be advantageous to use a system that sits above a number of transformers, optimising the network across that group. In order to control voltages within a traditional AVC it would be necessary to alter the voltage setpoint (within a predetermined bandwidth). As mentioned in Appendix D, this may be possible through the use of existing load-shedding voltage reduction techniques (where a 3% buck or boost can be applied) or through some other form of intervention with the AVC itself. Intervention can be in two forms, a) physically visiting the site and manually altering the setpoint by hand or b) utilising some form of remote control and functionality*, clearly the latter is preferred. Traditional Approach Without using the next layer of automated active management, a traditional approach can only be achieved with the provision of remote AVC operation at all relevant sites and a control engineer continuously monitoring and ‘tweaking’ the network setpoints to achieve network equilibrium. Whilst this is a sustainable for the current fairly limited levels of generation, it becomes increasingly difficult and costly as more and more generators connect. SCADA Approach The Optimal Power Flow (OPF) software seems the most suitable product for this purpose, which if implemented through SCADA would give a fully automated flexible solution. The following information (Overview to Summary) has been taken directly from literature of IPSA Power’s OPF [17]. Overview The OPF is a relatively new addition to the suite of tools that can be used in the design and analysis of electrical networks. There are many different variants on the OPF depending on the solution method and end-user requirements. At its simplest level, the OPF automates the normal iterative process that a normal study would take using a conventional power flow programme. For example, to determine the maximum load a particular node could take, the user would have to gradually increase the load until either a voltage or thermal limit is reached. This may take several iterations of the power flow programme and require the user to monitor many different system variables. On a simple system, this approach would usually result in a near optimal solution as there are only a few

* Fundamentals –working on behalf of VA Tech– are currently developing software to enable this on the MicroTAPP relay

- E15 -

variables that need to be monitored. The OPF however can do this same study in a single step while monitoring all the system constraints. The advantage is a significant saving in time taken to perform the study. For more complex systems with a large number of operational variables and system constraints, the OPF can still determine a near optimal solution whereas the corresponding time required for an experienced system analyst using a conventional power flow programme would be prohibitive in comparison. For example, the use of an OPF in a study to determine the optimal placement of DG and reactive compensation on a meshed network would significantly reduce the amount of time required. By initially identifying the potential nodes where generation could be added, the OPF would then adjust them all simultaneously to result in a solution that maximises the amount of generation without resulting in any system constraints. An OPF, like all simulation programmes, requires careful use to ensure reasonable results are obtained. It essentially automates the manual adjustment process thereby freeing the analyst to consider the overall picture. There are three key parts to an OPF formation: Objective Function – This defines the user definition of the optimal solution. It can consist of different system variables such as capacity changes and losses linked together by a common unit such as cost (£). Decision Variables – These are the variables by which the solution algorithm tries to maximise (or minimise) the objective function. They consist of two categories, state variables such as nodal voltages or angles, and control variables such as active and reactive generation or load shedding. Constraints – These define the satisfactory operating envelope of the network such as maximum and minimum output of a generator, voltage limits on a busbar, maximum power transfer down a line or transformer, etc. Formation of the IPSA-OPF The OPF used, that has been implemented in IPSA was originally developed by UMIST as part of a PhD project. The OPF has since been proven on a real 1000+ busbar transmission system. The objective function can consist of any one, or combination, of the following: • Active power generation dispatch • Reactive power generation dispatch • Active power generation capacity • Reactive power generation capacity • Load shedding • New branch capacity • Maximise network loading

- E16 -

The constraints that are put on the optimal solution are: • Nodal active power balance • Nodal reactive power balance • Operational voltage limits • Active and Reactive Generation limits • Load shedding limits It is also possible to allow certain system parameters to be modified during the optimisation process. This allows the solution additional scope with which to minimise or maximise the objective function. The controls that can be fixed or variable are: • Active power generation • Voltage control setpoints • Transformer tap positions • Quadrature boost transformer phase angles • Shunt reactance/capacitances

- E17 -

Summary The OPF programme is another tool for the power system engineer to use in order to determine the best system design and operation in terms of technical feasibility and least cost. Like all simulation tools, the OPF is not intelligent in its own right and so care must be taken in constructing the network model and interpreting the results. However, a properly configured OPF will significantly reduce the study workload of the engineer by removing the trial and error approach to determining the optimal network loading and capacity. The OPF can also highlight new operational network conditions that previously have not been considered due to limitations of the iterative approach using conventional power flow programmes. Implementation Whilst developed as a network design tool, OPFs have been successfully used on transmission networks operating in real-time. The development of a suitable OPF for improving network voltages in the presence of variable generation profiles or even managing generation constraints may be extremely useful for DNOs into the future. I/O Interface • The OPF software could be bundled into an engine (say a modern industrial

computer), which can be interfaced through the existing SCADA database in the Host machines (similar to many existing contingency analysis software packages).

• The outputs from the engine could be linked back through to the SCADA system, thereby giving the capability to disseminate signals back out to remote sites, Figure E11

The costs to develop and interface an OPF to the Host machine would have to be derived on a bespoke basis for each DNO.

- E18 -

Inte

rface

Static Database

Constraints

SourceMain SCADA

NetworkTopology

Dynamic Database

Input / Output

To Network RTUs

DecisionLogic

CommercialInformation

- Audit Trail -

ScanTables

API

API

Res

ults

Loadflow OptimiserVoltage Optimiser

Generation OptimiserA N Other Optimiser

New System Existing System

CommandAudit

OPF SoftwareEngine SCADA

Host

Figure E11: Implementation and Interface of an OPF System into the Existing SCADA

Network

E.4 SCADA Solution Discussion

The above solutions consider a number of options for development of Active Management using SCADA depending on the speed requirements, DNO’s network topology or SCADA architecture. All of the solutions focus on developments that will improve the existing SCADA system, and make SCADA an even more essential and integral part of the DNO’s capital infrastructure. Changes have been identified that can be achieved in a series of steps to ensure that the infrastructure (ie communications channels) is in place for possible future needs. Scheme / network flexibility has been considered throughout, so that should network developments occur, simple modifications can be made to suit without the removal of redundant equipment and installing additional products. The cost of rented communications will always be a major factor, with even analogue services attributing a substantial proportion of the total scheme cost. It can be seen from the service price lists on www.bt.com that rented digital communications are significantly more costly than their analogue counterparts. Should it be deemed necessary to have such channels in place, appropriate funding will be essential. These costs could be significantly reduced if the DNO were to install and operate their own digital communications infrastructure alongside their electricity network.

- F1 -

APPENDIX F – OVERVIEW OF DNOS SCADA ARCHITECTURE The information contained in this Appendix was gathered by Thales-IS (edited by the Author) for the purpose of this project. Whilst all UK DNOs were contacted, few felt in a position to release information about their SCADA networks. Those who replied have been included below, with many of the assumptions for the implementation of SCADA active management (made in this report) based on generalisations of these systems.

F.1 SP Manweb

In the SP Manweb Licence area, there is one SCADA system covering 132kV to 11kV.

F.1.1 Overview

Wide Area Network

DualSCADA Hosts

Terminal Server Terminal Server Terminal Server

9 off Districts

Modem Tier

PSTN Terminal Servers

NMS WorkstationNMS WorkstationNMS Workstation

DualNMS Hosts

NMS Workstation

Modem Tier Modem Tier

Main SiteMk3 Modular

Daisy-chained onBT leased cctsMulti-drop on

Manweb pilots

Remote RTU

1200 bps 2400 bps

2400 bps

Subordinate RTUsSubordinate RTUs

Scheme ControlUnit

SlaveUnit 1

SlaveUnit 2

Event Triggered Radio Communications

- F2 -

Figure F1: Current SCADA Control Room and District Architecture (Host System pending Alteration)

F.1.2 Architecture RTU data from Primary substations is picked up at marshalling points generally based at nearby Grid Sites. Two-way communications are typically established via four-wire copper lines (2400 or 1200 baud). The modems installed at each Grid Substation are capable of communicating with a number of RTUs. Multi-dropping is used throughout, but particularly in remote areas where communication channels are sparse (design limit of up to 12 per line). Multi-dropped lines run at 1200 baud only. The RTUs in the Grid Sites are linked up to one of a number of district terminal servers. Acting as main data hubs, each terminal server can communicate simultaneously with a number Grid Substation RTUs. Communications are full-duplex using four-wire copper lines (run at 2400 baud). A second, two-wire half-duplex PSTN (Public Service Telephone Network) line is supplied to each Grid Site RTU to backup the communications system, operating on a 10 minute delayed dial-up. The terminal servers all form an interconnected ring and feed onto the Wide Area Network. Digital (fibre optic and copper) channels are used to communicate between servers facilitating the high bandwidth requirements. There are two stand-alone SCADA host control systems located at two separate locations, which can be changed over in the event of failure of one system. There are currently, two software control systems used on the SP Manweb network. The 132/33kV networks are controlled by a Thales SCADA/NIMS, and are redundant with the two halves of the system on separate sites, which are connected by high-speed communications. Client HCI systems are also situated at both sites. The 11kV system is controlled by a GE Network Solutions (GENS) system with multiple on-line servers providing redundancy.

F.1.3 SCADA Components and Capabilities There are approximately 800 RTUs in the SP Manweb licence area, these predominantly run a variant of Ferranti protocol, the RTUs and have no DCL capability but can execute sequence of controls down loaded from SCADA Host in advance. New or refurbished larger substations are being installed with Substation Control Systems (SCSs) using one of the new ‘standard’ protocols, which is converted to emulate the Ferranti protocol to converse with the main SCADA network. • Line speeds are 1200 baud multidrop or 2400 baud re-generated. • Design figure is 8 RTUs per multidrop though in practice 10 is common. • Design figure is 5 for regeneration.

- F3 -

There are approximately 140 11kV-automation systems currently being installed on key circuits for supply restoration. These use controllers with logic sequence capability at the Primary substation communicating over event triggered radio to remote sites (both pole and ground mounted substations / open points).

- F4 -

F.2 SP Distribution (ScottishPower)

F.2.1 Overview As a Scottish DNO, SP Distribution covers voltages from 33kV to LV – the 132kV network is considered a part of the SP Transmission network.

ENMAC 1 ENMAC 2 ENMAC 1

Main SCADA Host Standby SCADA Host

Dual 2MBps links

Ethernet EthernetDual 2MBps link

Ethernet Ethernet

Terminal Servers(16 ports per server)

Ethernet Ethernet Ethernet

Radio / Modemat HIllsites

RTU Mk4RTU

Mk3RTU

RepeaterRTU

PSTN / PABXNetwork

Modem Rack

1200 Baud

2400 1200

BSP S/S

Radio / Modem

RTUApprox.

120 radio sites

2400 Baud

SlaveUnit 1

SlaveUnit 2

Event Triggered RadioCommunications

Radio / Modem

RTU

Scheme ControlUnit

1200 Baud

Figure F2: SCADA Architecture for the SP Distribution Network

F.2.2 Architecture The 11kV circuit breakers at the Primary substations are controlled by a different variant of Ferranti protocol to those of SP Manweb, RTUs are typically on 1200-baud lines. The RTUs are scanned by dual redundant Hosts, with dual redundant software supplied by Thales and application software by Thales and GE Network Solutions (GENS). There are three key sites containing terminal servers that are connected to form a ring and feed onto the Wide Area Network. Digital (fibre optic and copper) channels are used to communicate between servers facilitating the high bandwidth requirements.

- F5 -

The RTUs in the Bulk Supply Point (BSP) substations are linked to one of the three terminal servers. Acting as main data hubs, each terminal server can communicate simultaneously with a number BSPs. Communications are direct from the digital network to every RTU using a mixture of copper lines (run at 1200/2400 baud) and radio (run at 2400 baud).

F.2.3 SCADA Components and Capabilities There are approximately 400 RTUs in the SP Distribution Licence area (NB: 33kV to LV), using predominantly the Ferranti protocol. These contain some sequence capability, and have Distributed Control Logic (DCL) capability, however this is not currently used by SP Distribution. • Line speed is typically 1200 baud on 4-wire, 2400 baud on radio. • Circuits are radial with up to 12 RTUs on a radial node. The GENS ICOND system can implement broadcast controls (eg Load Shedding). Sequence switching is not available in the current system. There are approximately 80 11kV-automation systems currently being installed on key circuits for supply restoration. These use controllers with logic sequence capability at the Primary substation communicating over event triggered radio to remote sites (both pole and ground mounted substations / open points).

- F6 -

F.3 Aquila Networks (Midlands Electricity)

F.3.1 Overview This SCADA system provides fully integrated 132/33/11kV control together with integrated Outage Management. The whole of the LV network is captured in a GIS system and fuse positions etc are kept up to date dynamically by mobile GIS terminals used by maintenance crews.

Terminal Servers

Terminal Servers

SCADAServers

NIMS/ DatabaseServers

Asset ManagementSystem

Network ModellingServers

Remote Telemetry Units

PRMARY CONTROL SYSTEM: Dual Redundant Servers

400 RTUs30,000 Analogues, 80,000 Plant Items

Historical DataSystem

��

SMS Text MessageSystem

DatabaseServer

Remote Clients(Intranet)

Remote Clients(Dial-in)

SECONDARY CONTROL SYSTEM: Clustered Servers

Shared Clients

��

Private Mobile Radio

ApplicationServer Disaster Recovery

Lightening Tracker

Operator Clients

Large Screen

Figure F3: Aquila SCADA Overview

F.3.2 Architecture The 132/33kV systems are controlled by a Thales SCADA/NIMS system. The architecture is based upon Hewlett Packard servers one for SCADA and one for the NIMS system (HCI server/diagram). Both servers are fully redundant and on separate sites connected by the corporate LAN. There are a large number of client HCI workstations that are distributed around the enterprise on the corporate LAN. The SCADA and NIMS servers do not work in pairs but can operate together in any combination. The RTU communication lines are brought onto the corporate network at various points by modems and terminal servers. The 11kV network is controlled by a Client Server based system supplied by M3i of Canada. The servers are redundant. Each server is sited with a SCADA/NIMS

- F7 -

combination described above. Clients are distributed around the network. There is a highly functional interface between the Thales and M3i systems. Measurements, switch states, controls and safety data are exchanged between the two systems. The M3i system is also fully integrated with the outage management system.

F.3.3 SCADA Components and Capabilities A variant of Ferranti protocol is used for 132/33kV with 1200 baud multi-drop communications via private wire and radio. This particular protocol has no sequence capability. There are 300 plus Ferranti RTUs, mainly on primary network. These were originally supplied by Thales in early 1980s, but are now being replaced by RTUs from VA Tech that emulate this Ferranti protocol. 11kV urban and rural automation schemes are currently being implemented. These are PC based logical RTUs (Ferranti protocol scanning to DMS). These communicate with up to 15 rural/urban RTUs by one of the more modern protocols. A database is maintained to de-synchronise the two scanning systems. The RTUs are grouped in small clusters of 2 or 3 and provide local sequence switching operations; these RTUs communicate between each other to provide automatic switching (rather than being controlled by the PC).

F.3.4 Communication Network details Ferranti protocol communications at 1200 baud, multi dropped lines over private copper, radio (mainly rural network), MUXs and private BT Pilot cable to urban subs. Large urban subs are connected by dual lines, which automatically switch every half-hour (controlled by DMS). Urban/Rural 11kv networks utilise PAKNET (dial up cell network).

- F8 -

F.4 Northern Electric Distribution (Northern Electric)

NE’s 132/33/11kV systems are controlled by a GENS ENMAC system. The architecture comprises a front end SCADA computer with a back end HCI computer for the diagram etc. The system is fully redundant. Each pair of computers may be on the same site or distributed on a high speed LAN.

F.4.1 RTU Types GEC Perm with a Ferranti protocol emulation for 132/33kV 1200 baud communication. They are being (have been) replaced by Microsol RTUs utilising the one of the new ‘standard’ protocols, and are thought to have sequence capability. Ferranti variant plus other (?) RTUs for rural automation, with connectivity via data concentrators. No other information is known.

F.5 United Utilities Electricity (NORWEB)

This system provides fully integrated 132/33/11kV control together with integrated Outage Management. The UU 132/33/11kV systems are controlled by a Thales SCADA/NIMS system. The architecture is based upon Compaq Tru64 SCADA & NIMS servers and multiple Compaq Tru64 HCI clients. Data acquisition from RTUs is via distributed front-end processors/data concentrators (seven sites). Both SCADA and NIMS servers are fully redundant and on separate sites connected by an FDDI corporate WAN. There are sixty client HCI workstations that are distributed around the enterprise on the FDDI network and corporate LAN.

F.5.1 RTU Types GEC SCOUTs for 132/33kV 1200 baud multi-drop communications via private wire and radio (proprietary TC57 based protocol). Despite being relatively old, the RTUs have modern functionality including sequence switching. They may be replaced by Microsol RTUs using one of the new ‘standard’ protocols, which are supported by the SCADA system. They have sequence capability using an IEC standard. Rural automation RTUs from Remsdaq are being installed using radio communications and data concentrators. No other information is known.

- F9 -

F.6 East Midlands Electricity

A pioneer in the early 1990s of integrated Network Management Systems for EHV, EME have recently migrated to a GENS system for controlling the 132/33kV network. This is based on Compaq Tru64 servers with NT clients. The 11kV remains managed using wall diagrams. The SCADA system is based upon a centralised high availability SCADA/DMS with the communications terminating at the central site. There is a disaster recovery system at a remote site connected by high-speed communications. In the event of this system being called into use, the communications to the RTUs are diverted to this site.

NMS (ENMAC)

FEP

LSU

LSU

Modem

��

��

Data Concentrator

Poletop and ground mounted field devices (≅ 400 –800). Communiqueradios.

33Kv (Primary) Substations (≅ x sites, mainly Zodiac radios)132Kv Substations (minority)

Line Connected Transparent Scan Groups

400/275Kv Bulk Supply Substations(≅ 12 sites)

132Kv Substations (majority, 80 –90 sites)

EMNET

I

GSM SMS

Poletop Fault Passage Indicators

BT BT

BT

≅ 500

EMNET or BT

EMNET or BT

Appears to NMS as 4 RTU ports

Can scan up to 80 RTUs

Transparent Radio Scanners

‘SL’ Process (implements SCADA protocol )

FEP Ports

Concentrator Radio Scanners

Figure F4: Overview of EME SCADA Network

F.6.1 RTU Types A Ferranti variant protocol for 132/33kV with 1200 baud multi-drop communications via private wire and radio. This Ferranti protocol has no sequence capability. Also a Westronic protocol RTU with the Ferranti variant emulation. Harris re-engineering Ferranti Emulation for the Ferranti replacement with D20s (or modern equivalent). Rural automation RTUs are being installed utilising a Ferranti protocol type of data concentrators. Initially RTUs were a variant of Ferranti but now also from Newlec. Radio communications are being used. All have sequence control capability.

- F10 -

F.7 Other DNOs

Knowledge of other UK DNOs SCADA infrastructure is limited, however, the list below covers some rough details of their Control or RTU types.

F.7.1 SSE Power Distribution (Scottish Hydro Electric) GENS ENMAC system at voltage levels from 275kV to 33kV. No other information is known.

F.7.2 EDF Energy Networks (Eastern Electricity) A combination of Ferranti variant and Westinghouse RTUs are installed for 132/33kV with 1200 baud multi-drop communications via private wire. Westinghouse protocol is being used with sequence capability. No other information is known.

F.7.3 YE Distribution (Yorkshire Electricity) No information known.

F.7.4 EDF Energy Networks (SEEBOARD) Westinghouse RTUs installed for 132/33kV with 1200/2400 baud multi-dropped communications. No other information is known.

F.7.5 SSE Power Distribution (Southern Electric) Westinghouse RTUs installed for 132/33kV with 1200/2400 baud multi-dropped communications. GENS ENMAC used. No other information known.

F.7.6 EDF Energy Networks (London Electricity) Remsdaq RTUs are installed for both 132/33kV and rural automation. No other information is known.

F.7.7 Western Power Distribution (South Western Electricity) Harris RTUs are installed for 132/33kV with 1200 baud multi-drop communications. No other information is known.

F.7.8 Western Power Distribution (SWALEC) Harris RTUs are installed for 132/33kV with 1200 baud multi-drop communications. No other information is known.

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