ACTIVE NETWORK MANAGEMENT (ANM) TECHNOLOGY Current Technology Issues and Identification of Technical Opportunities for Active Network Management

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1 ACTIVE NETWORK MANAGEMENT (ANM) TECHNOLOGY Current Technology Issues and Identification of Technical Opportunities for Active Network Management CONTRACT NUMBER: DG/CG/00104/00/00

2 CURRENT TECHNOLOGY ISSUES I AND IDENTIFICATION OF TECHNICAL OPPORTUNITIES ORTUNITIES FOR ACTIVE NETWORK MANAGEMENT (ANM) ( CONTRACT NUMBER: DG/CG/00104/00/00 URN NUMBER: 08/621 Contractor Sinclair Knight Merz The work described in this report was carried out under contract as part of the BERR Emerging Energy Technologies Programme, which is managed by AEA Energy & Environment. The views and judgements expressed in this report are those of the contractor and do not necessarily reflect those of the BERR or AEA Energy & Environment. First published 2008 Crown Copyright 2008

3 EXECUTIVE SUMMARY This project was sponsored by the Distribution Working Group (DWG), an industry group seeking to prepare distribution networks in Great Britain for a low carbon future. The project has considered current technology issues and opportunities with regards to active network management (ANM), and produced a practical set of recommendations aimed at enabling a near term increase in ANM. A separate DWG project underway at time of writing will consider non-technical ANM barriers and opportunities. It is found that there are currently no significant technical barriers to ANM. Generally, new technologies follow a path from academic research, through to desktop simulation, development, pilot projects, large scale trials and then eventually to full implementation. A literature review found that a large body of work exists on the subject of ANM technologies, and that many new technologies are nearing the latter stages of development in the UK. Various industry working groups and regulated incentive schemes, in particular the IFI and RPZ 1 mechanisms have been reasonably effective in encouraging Distribution Network Operators (DNOs) and manufacturers to bring forward ANM pilot projects. However, ANM appears to remain a somewhat niche area of development for DNOs. Several promising technologies for facilitating ANM were considered for detailed assessment. Particular emphasis was made on the operational robustness of different technologies, ie the impact of integrating a new technology into the existing network. For this project, a technology was defined as a new device, an existing device that could be used in a different way or a new system, method or practice that might enable ANM. The chosen technologies were: Inline voltage regulators SVCs and STATCOMs Active voltage controllers Dynamic line rating systems Each of these new technologies or new applications of an existing technology has or is currently undergoing a trial phase somewhere on the network. They are each therefore available commercially now or expected to be in full commercial mode within the next 5 years. It should be noted that this is not an exhaustive list of such technologies. An overview was given of each technology, and then they were assessed against the following factors: Technical functionality and barriers Operational impact Planning impact 1 Innovation Funding Initiative (IFI) designed to encourage research and development, and the Registered Power Zone (RPZ), also to encourage research and development but specifically in relation to connecting distributed generation ii

4 Other issues, including eligibility for IFI/RPZ funding It is found that each of the four technologies could be an appropriate solution to certain network problems in particular circumstances. It is therefore recommended that DNOs make the necessary changes throughout their organisations to incorporate these technologies into their standard kit of solutions when considering options for network investment. This will provide the DNOs with greater flexibility to meet network needs, particularly DG connections. However, greater flexibility might also represent a new challenge for DNOs who have traditionally been used to dealing with a more limited set of options. It is recommended that manufacturers seek to work closely with DNOs across all areas of their businesses to help fully implement new technologies. Particular attention needs to be paid to the planning department of a DNO business where many of the investment decisions are made, and where new tools and a fuller understanding of the impact of the new technologies might be required. The importance of full demonstration of a project to DNOs (who are driven in large part by security, reliability and safety) is also emphasised, as is the need to reduce the cost and complexity to implement, operate and maintain products that are new to the organisation. It is recommended that the RPZ and IFI schemes be revised to provide an incentive for DNOs to take up the best technologies trialled by other DNOs, thus propagating best practice throughout the industry. DNOs should conduct regular reviews of their network to determine if there are any opportunities to gain benefit from implementing new technologies under these schemes. In addition, the DWG might be able to play a role in coordinating DG developers and DNOs to find suitable areas of the network to implement an RPZ. Such areas must have particular network conditions and be attractive to developers. Existing Electricity Networks Association (ENA) guidelines, ETR 124 and 126, on implementing ANM technologies were originally a useful summary of possible solutions but now appear lacking in detail. Ideally, these will be updated following successful completion of the various trial programmes currently underway on the network. In addition, the existing technical standard defining network voltage limits might benefit from a review to cater for the changing network conditions, particularly increasing amounts of distributed generation and ANM. Finally, it is recommended that all future projects sponsored by the DWG include an update of the ANM pilots and trials register developed under a previous DWG project. iii

5 CONTENTS Executive Summary... ii 1 Introduction Aim of the Project Definition of ANM and ANM Technologies Methodology Summary of Issues Driving ANM Technical Regulatory and Commercial Drivers Literature Review Existing ANM Outcome of the Existing Practices Report Results of the IFI and RPZ Mechanisms Innovation Funding Initiative (IFI) Registered Power Zones (RPZ) Effectiveness of the RPZ/IFI Mechanisms Literature Review New and Emerging Technologies Common Themes New Technologies Report ANM Register Other Projects of Interest from the ANM Register ENA Reports Dynamic Equipment Rating Control DGFACTS Selection of Technologies for Appraisal Primary Plant Secondary Plant Rejected Technologies Technology Appraisal Assessment Methodology General Technical Operational Planning Other Detailed Analysis Inline Voltage Regulators Overview Technical Issues Operational Issues Planning Issues Other Issues Synchronous Compensators: SVCs and STATCOMs Overview iv

6 6.2.2 Technical Operational Planning Voltage Control by Active Controllers Overview Technical Operational Planning Other Dynamic Line Rating Overview Technical Operational Planning Other Summary of Results Recommendations Introduction Manufacturers General Inline Voltage Regulators SVCs and STATCOMs Active Voltage Controllers Dynamic Rating Systems DNOs Integration of New Technologies and Practices Regular Network Reviews Specific RPZ Opportunity Asset Replacement DG Developers IFI/RPZ Schemes Technical Standards for Voltage ENA Guidelines DWG Conclusions Appendix A Project P01 Active Network Management Definitions... 1 Appendix B Glossary... 1 Appendix C Sample Questionnaire... 2 v

7 1 INTRODUCTION The Electricity Networks Strategy Group (ENSG) is an electricity industry group sponsored by the Department of Trade and Industry (now the Department of Business Enterprise and Regulatory Reform, BERR) and Ofgem. It seeks to identify, and co-ordinate work to address the technical, commercial, regulatory and other issues that affect the transition of electricity transmission and distribution networks to a low-carbon future 2, and builds upon previous similar programmes. The Distribution Working Group (DWG) is a subgroup of ENSG, coordinating a number of projects in various work streams specifically aimed at distribution networks. One of these streams, Work Programme Three, Enabling Active Network Management, considers the ways in which Distribution Network Operators (DNOs) can actively manage their network to better facilitate low carbon power systems with efficient use of investment. Sinclair Knight Merz (SKM) was commissioned to support Work Programme Three - Project Six: Current Technology Issues & Identification of Technical Opportunities for Active Network Management (ANM). 1.1 Aim of the Project The aim of this project is to summarise the current known technology issues and identify potential technical opportunities in undertaking active distribution network management 3. In particular, the aim is to produce a practical set of recommendations that might lead to some immediate action, whether by DNOs, manufacturers, the regulator or other stakeholders. Particular emphasis was made by the DWG Project Team on assessing the operational robustness of different technologies, ie the impact of integrating a new technology into the existing network. A separate DWG project, Work Programme Three, Project Five: Addressing Current and Emerging Commercial, Legislative and Regulatory Barriers, underway at the time of writing this report, will consider non-technical issues. The scope of this project was limited to technologies intended to apply in the voltage range of 11 kv to 132 kv and either available now or expected to be in full commercial mode within the next 5 years. 1.2 Definition of ANM and ANM Technologies Programme 3 Project 1 produced a definition of Active Network Management (ANM), which is included in Appendix A. This can be summarised as: ANM means devices, systems and practices that operate pre-emptively to maintain networks within accepted operating parameters. ANM may be compatible with automation of the network to speed supply restoration following an abnormal event, and increased visibility and control of the network to facilitate management practices 4. For this project, a technology is defined as: From the project brief 4 Modified from A Technical Review and Assessment of Active Network Management Infrastructures and Practices, EA Technology,

8 a new device; an existing device that could be used in a different way; or a new system, method or practice, that might enable ANM. 1.3 Methodology The methodology was as follows: 1. A review of the recent relevant Work Programme reports. a) Work Programme 3, Project 3 (the Existing Practices Report ), completed by EA Technologies Ltd 5 ; b) Work Programme 3, Project 4 (the ANM Register ), completed by University of Strathclyde 6 (and a review of the reports referenced in the register); and c) Distributed Generation Coordinating Group Workstream 5, Project 10 (the New Technologies Report ), completed by PB Power A review and summary of current ANM initiatives undertaken by DNOs. 3. A number of technologies were selected for further appraisal from the New Technologies Report and the ANM Register, taking into account how they would fit into the distribution networks as identified in the Existing ANM Practices report. The DWG project team were provided with an interim report at this stage and hence consulted before finalising the selection. 4. A set of criteria for evaluating the technologies was developed and also discussed with the project team, and this is presented in this report. The criteria were based on the priorities of the DNOs in the areas of operability and key parameters such as safety, the environment, operating and maintenance costs and reliability of supply. 5. Questionnaires were sent to manufacturers of the chosen technologies where there was not sufficient data available from the literature review (Areva, GE Energy and ABB). The format of the questionnaires is given in Appendix C. 6. The technologies were then considered against the evaluation criteria. 7. Recommendations were made based on the resultant findings. 5 A Technical Review and Assessment of Active Network Management Infrastructure and Practices, EA Technology, 2006 [Existing Practices Report] 6 Register of Active Management Pilots, Trials, Research, Development and Demonstration Activities, University of Strathclyde, 2006 [ANM Register] 7 New Technologies to Facilitate Increased Levels of Distributed Generation, PB Power, 2006 [New Technologies Report] 2

9 1.4 Summary of Issues Driving ANM Technical One of the most significant recent changes to distribution networks that are driving closer examination of the potential benefits of ANM in Great Britain are increasing levels of Distributed Generation (DG), particularly wind generation. The impacts of increasing levels of DG on traditionally passive distribution networks have been well documented, and consist primarily of: Increased fault levels, potentially exceeding equipment fault level ratings; Increased power flows, potentially exceeding equipment thermal ratings; and Changing power flows, potentially causing voltages at various places on the network to deviate from acceptable levels. It is expected that carbon polices, energy prices and other factors will drive not only DG but also increased levels of Demand Side Participation (DSP) from customers or their suppliers. This might also place additional technical demands on the network, primarily in the form of a need for greater levels of status information. Although load growth in Great Britain is relatively low, pockets of the networks are experiencing significant load growth. The increased power flows can cause problems with exceeding equipment thermal ratings, and/or causing excessive volt drop. In heavily urbanised areas (such as inner-cities), access to some DNO assets can be difficult due to transport, infrastructure density (such as other services in the same location) and other logistical difficulties. This might provide incentives to increase levels of automation to avoid delays sending personnel to the site, which is turn relates to regulatory penalties and incentives to improve reliability. Finally, the age of the UK networks means that a significant amount of the equipment installed in the post war period of network expansion is reaching the end of its lifetime, triggering large asset replacement programmes. This provides both a problem to be resolved and funded but also an opportunity for DNOs to introduce new technologies Regulatory and Commercial Drivers DNOs, like any business, have a commercial imperative to meet both current and future customer (end consumer, load and generation developers) needs and expectations. Improving the quality and reliability of electricity supplied to end customers has driven some of the major changes in distribution networks since privatisation, and safety for staff, the public and the environment is a key concern. In addition, there are regulatory drivers on DNOs, including those resulting from the price control process. Active networks might help reduce or defer capital expenditure in some situations, but until recently the facilitating technologies have often been seen as new and unproven, and it is not always easy to compare the lifetime costs of active networks with traditional reinforcement schemes. There is some doubt about whether the price control mechanism gives appropriate signals with regards to a lower capex but higher opex and shorter lifetime active network solution. 3

10 Active network design and planning to date has proved to be far more time consuming than traditional reinforcement methods. Ofgem and the DNOs are already considering how the balance between opex and capex drivers might change in the next price control period, which will potentially strengthen the drivers for ANM. These matters are being further considered in Project Five. In 2005, Ofgem created two new incentive schemes to encourage DNOs to explore novel methods, known as the Innovation Funding Initiative (IFI) and Registered Power Zones (RPZ). IFI provides a level of funding to DNOs for research and development projects aimed at delivering value to end consumers. The RPZ mechanism builds upon the existing DG mechanism which encourages DNOs to reduce the cost of deep reinforcements. The RPZ specifically provides an additional incentive to DNOs to connect generation in an innovative way. For the RPZ and IFI schemes, innovation is measured by Ofgem in accordance with published criteria 8. In assessing ANM technologies, this report considers whether they meet the criteria for funding under these two schemes. Another regulatory driver is the security standard P2/6 and the related key performance indicators of Customer Minutes Lost (CML) and Customer Interruptions (CI) and their associated financial penalties and incentives. The benefits of technologies that can make an impact on CML and CI can be readily quantified, and hence make the decision making process of whether to implement a new technology simpler and faster than if the benefits are less tangible. 8 ENA Engineering Recommendation G85, Electricity Networks Association, 2005 [ER G85] 4

11 2 LITERATURE REVIEW EXISTING ANM 2.1 Outcome of the Existing Practices Report The aim of Programme 3 Project 3 project was to review and document the current approaches and infrastructures for network monitoring and active operation control across the DNOs. The authors surveyed the DNOs to determine what control and communications equipment was employed across the network at the time of the survey, as well as more specifically what ANM practices were being used. The report also considered new technologies and potential barriers to their implementation. One of the key findings from this report was that DNOs currently and increasingly have large numbers of intelligent electronic devices (IED), such as programmable protection relays, embedded in their system which could be used as key components in a system to provide greater levels of active control over parts of the network but whose functionality potential is largely untapped. 2.2 Results of the IFI and RPZ Mechanisms Innovation Funding Initiative (IFI) The DNOs have initiated a number of projects under the IFI mechanism, including projects considering ways to allow more generation onto the network with less capital cost than traditional solutions. A small selection of ANM projects relevant to the technologies being considered in this report is given below. More information is found in each of the DNOs annual IFI reports. DNO Collaborative Aura-NMS project Collaborative Strategic Technology Programme Collaborative EDF EDF E.ON Central Networks E.ON Central Networks E.ON Central Networks Project Description Development of an integrated and repeatable active controller Several projects aimed at enabling connection of DG Investigation of superconducting fault current limiters Development of state estimation algorithms for the whole distribution system Electricity storage and DSP technologies Integrated sensor and monitoring system for advanced distribution automation Research and development for a solid state power transformer Investigation of magnetic fault current limiters Scottish Power North Wales inline voltage regulator to facilitate DG connection 9 Scottish Power Scottish Power Development of a battery system for energy storage Trial of a new voltage control relay using measurements from DG feeder current transformers to refine overall Automatic Voltage Control (AVC) relay response 9 Modelling the Interaction Between an In-Line Voltage Regulator and a Doubly-Fed Induction Generator, Tegni Cymru Cyf, EA Technology, SP Power Systems, UMIST,

12 Scottish Power Scottish and Southern Energy Scottish and Southern Energy United Utilities Thermal modelling and development of a dynamic ratings system Study to determine if energy storage will allow more renewable generation to connect on the isolated Shetland Island network Development of a distribution power electronics voltage regulator for the 11 kv and 33 kv networks Development of a software tool for fair allocation of distribution losses to DG Registered Power Zones (RPZ) The RPZ mechanism has triggered three projects to be registered with Ofgem to date, namely: Orkney Islands active network management (33 kv) Scottish Hydro Electric Power Distribution Skegness & Fens dynamic line ratings (132 kv) Central Networks (E.ON) Martham Primary GenAVC voltage control in Norfolk (11 kv) EDF Energy The existing RPZ projects are of particular relevance to this study as they provide some of the only real demonstrations of the use of ANM in the UK. Scottish Hydro Orkney Islands RPZ The Orkney Islands has recently seen a rapid expansion of connected DG due to its significant renewable energy resources 10. Changing from being a net importer to a net exporter of electricity caused a number of problems. The first was significant voltage rise on the island s 33 kv network as well as the two main subsea cables connecting the island to the mainland and radial feeders out to smaller islands with connected generation. These voltage problems were resolved by installing a dynamic VAr compensator (DVAr) and shunt reactors for the more localised voltage problems on the radial feeders. The DVAr had the added advantage of providing a local controllable source of reactive power to address what would have otherwise been short term voltage excursions on changing demand and supply patterns. The authors of the report on the scheme considered the introduction of the DVAr onto the network a success. The second problem encountered on Orkney with increasing amounts of connected DG was that of exceeding thermal limits. This problem was solved primarily through commercial means, enabled by standard and communication technologies (although using quite novel logic sequences). Extensive power simulation studies were done to create a range of scenarios which were then converted into ladder logic for the controllers. Generator maximum outputs were then controlled on the basis of last on, first off to keep the system within the theoretical limits determined by the studies. As the maximum transfer capacity of the subsea cables has already been reached by existing generation, new generation must fit into the gaps created by the intermittency of existing generation and increasing load, which is managed by the ANM scheme. 10 Facilitate Generation Connections on Orkney by Automatic Distribution Management, Scottish and Southern Energy,

13 An interesting feature of the ANM is that the decision was made to set the generation limit based on thermal limit of both subsea cables in operation. A more conservative, traditional approach might have been to set the limit at the limit of the lower rated cable, which would have effectively halved the total allowable generation. The report on the scheme notes that these cables have never experienced a fault. In the event of one of the cables tripping, the ANM scheme trips sufficient generation to remain within the thermal limit of the remaining cable. This intertripping scheme operates before the overcurrent protection on the second cable, which has sufficient time delays to allow this to occur. The ANM on Orkney Island also incorporates dynamic load switching, which has been in place since before the increase of DG beyond capacity of the main feeders, using publicly broadcast radio signals. A key ongoing concern regarding this ANM scheme will be logic complexity. Each new DG and each change in configuration of the network is likely to require changes to the logic controlling the scheme. Although the cost of actually making the changes for each new scheme might be capitalised, it is likely that the scheme will also impact on the operational expenditure of the DNO with additional switching complexity, resources, training, contract administration with the DGs and so on. The result of this scheme will be to allow generation to connect to the network up to the economic levels determined by the amount of time that generation is likely to be constrained. Without this scheme, an expensive new subsea cable would be required before additional DG could be connected. It should be noted also that this scheme exploits the intermittent nature of wind generation. E.ON Central Networks Skegness RPZ The trigger for the Central Networks RPZ was a series of generator connection requests near a line that did not have sufficient thermal capacity when determined using traditional rating methods. Traditional line rating methods in accordance with Engineering Recommendation P17 make conservative assumptions regarding ambient temperature, which results in a reduced allowable power flow than theoretically possible for most of the time. Calculations by E.ON 11 showed at best a doubling of line capacity between the best case predicted by traditional methods (ie the winter rating) and the best case likely to occur with real time dynamic rating. This scheme will be implemented by using two weather stations to feed back data to the existing central control system (using the ENMAC SCADA system), which will then dynamically calculate the ratings to the lines. After determining the ratings, the modified control system will take action to constrain the generators if necessary. As an additional safeguard, the scheme will use a device to measure (rather than calculate) actual line temperature and sag. This will be used to verify the dynamic rating calculations and the location of the weather stations. Without this scheme, as with the Orkney scheme, an expensive new line with new wayleaves would be required before the new DG could be connected. Again, this scheme exploits the particular characteristics of wind generation, but this time to use the high 11 An Introduction to Central Networks RPZ, Martin Orme, E.ON, presented at the IET Active Networks Workshop

14 coincidence of high power output with high wind speed leading to lower conductor temperatures and associated higher line ratings. A final similarity with the Orkney project is that it relies on contractual arrangements with the generators to constrain them down on a last on, first off basis. The cost of this scheme has been estimated at 270,000 to connect 90 MW of additional generation capacity 12. It should be noted that EDF have also implemented a dynamic ratings scheme using weather stations and the Power Donut on 132 kv lines to avoid reinforcement costs following connection applications from wind generators. EDF Energy GenAVC Martham Primary RPZ The Martham Primary RPZ is one of the test sites for the GenAVC product being developed by Econnect and has been registered as the third RPZ. Under previous programmes of the DGCG and the DWG and other such activities, a considerable amount of research has been directed towards developing algorithms to actively control the AVC relay setpoint at primary substations so that voltages are maintained within limits at all parts of the downstream network even when DG is connected. The GenAVC is one of the results of that research effort. It has successfully been actively controlling the voltage for the Martham 11 kv network since late As a further part of this project, an assessment tool is being developed 13 to allow planners to determine whether GenAVC was appropriate in any given place. EDF are now planning to trial a commercial version of GenAVC at another site at Steyning where a DG is experiencing trips at times of low load. Before making this decision, EDF supplied network data to Econnect, who verified the output of the assessment tool using system studies. It should be noted that the GenAVC has also been installed at a location on the United Utilities network. In addition, EDF and Scottish Power are involved in a similar project being developed by ABB, the AuRA NMS. Other RPZ Studies Although other DNOs besides those mentioned above have undertaken various studies to determine if they can also take advantage of the RPZ scheme, no others have been registered. In particular, CE Electric UK commissioned a study by Econnect to examine the feasibility of setting up RPZs in two areas using energy storage technologies to avoid other forms of network reinforcement. 14 The studies concluded that such an approach was not economically feasible at that time. 12 New Power Zones will Connect More Renewable Generators to the Electricity Network, Ofgem Press Release, EDF Energy Networks Ltd IFI/RPZ Report for EPN/LPN/SPN, EDF Energy, Registered Power Zones, Assessing the Feasibility of Establishing Power Zones on Northern/Yorkshire Electricity Networks, Econnect,

15 2.3 Effectiveness of the RPZ/IFI Mechanisms The RPZ and IFI schemes have successfully triggered greater levels of ANM activity than was occurring previously, and several ANM technologies are now entering the full demonstration mode because of these initiatives. It remains to be seen if these demonstration projects will lead to widespread adoption of the technologies. An important feature of the RPZ mechanism is that the innovative technology or use of a technology must not have been used before in the UK. This might encourage a broad spectrum of new technologies and approaches and do nothing to ensure the most successful are propagated amongst the companies. 9

16 3 LITERATURE REVIEW NEW AND EMERGING TECHNOLOGIES 3.1 Common Themes The literature review found reasonable correlation between the technologies identified and discussed. One notable feature that emerges from the documentation on ANM and the related topics of increasing distributed generation and load management is that despite this considerable research effort, there is little evidence world-wide of a major shift towards implementing ANM. ANM appears to remain a somewhat niche area of development for DNOs. In general, the most mature efforts in the UK appear to have been in the area of voltage control, followed by overcoming thermal limits. This is probably in part because these two factors are often the first limits when connecting DG. The literature review found that the DNOs have several intelligent devices that could facilitate greater ANM, but that they have largely not used the functionality of these devices or adopted the necessary systems and processes to do so. Some reasons for this have been suggested, and this issue is examined in more detail later in this report. 3.2 New Technologies Report The DG Coordinating Group (DGCG) preceded the DWG. Workstream 5 Project 10 project, of which the New Technologies Report was the outcome, was designed to address the following principle objectives: To identify what new technologies are available or emerging (in UK and world-wide) to facilitate increased levels of DG in the time frame to 2010; and To provide a summary of the status of emerging technologies to help inform decisions about what further work might be appropriate in this area. The New Technologies Report recommends a number of technologies for further study where the technology development is sufficiently advanced and of sufficient benefit in terms of allowed increased levels of DG to connect to the networks. These recommendations have been the basis for some of the technologies chosen for consideration in this report. The recommended technologies from the New Technologies Report are: Inline voltage regulators Inline voltage regulators are an established technology; however they were included in that report due to their current limited use in the UK despite potentially offering advantages in the area of voltage control. They are referenced in the ENA guidelines on voltage control with connected DG. FACTs Devices SVCs and STATCOMs have traditionally been used on transmission systems to provide reactive power and other forms of network support, and they are proven technologies. Their use at the distribution level has been virtually non-existent due to their cost, perceived complexity and possibly some apprehensions about the state of 10

17 development of the technology. However a number of manufacturers have been developing smaller scale systems specifically aimed at the distribution network market. Micro-grid controllers Several reports commissioned as part of DGCG or DWG workstreams 15 and a number of studies referenced in the ANM Register have suggested means of actively controlling voltage and power flow using new control algorithms, without requiring significant capital investment and using hardware that effectively exists now. Of particular interest will be the availability of Plug and Play devices that can avoid the problem of an excessive customisation burden on DNOs. Two micro-grid controllers in the UK are known to be currently under development. Super-conducting fault current limiters Of the four recommended technologies, superconducting fault current limiters seem to be furthest from commercial application in the UK. However, the authors concluded that manufacturers are close to providing fully tested solutions, and would do so within 5 years. Given the issues of high cost and long lead time of traditional network reinforcement and the increasing frequency of fault level problems, it seems reasonable to suppose that market pull might be a factor with this technology. Their ability to gain acceptance in other markets, particularly North American markets, provides hope that any perceived safety and reliability issues in the UK can be resolved. The DWG Work Programme 2, Project 9 is specifically aimed at investigating fault current limiting technologies to determine if they can be used in the UK. Therefore, to avoid overlap they will not be considered further in this project. 3.3 ANM Register The aim of Programme 3 Project 4 was to provide a clear statement of the status of recently completed, ongoing and planned active network management field pilot and trial activities, international developments in related areas, and research, development and demonstration activities. The project resulted in a comprehensive register of ongoing ANM Pilots, Trials, Research, Development and Demonstration Activities, demonstrating extensive body of literature being generated world wide regarding ANM and related topics. The register provides information on 105 novel ANM techniques and devices, as well as a variety of overarching programmes being run by different organisations world-wide. The majority of the activities identified were in the theoretical, research and development stages, with the remainder describing systems or devices in various stages from desktop studies through to full commercialisation. A large number of projects concentrated on control and communication issues. The ANM Register has been a valuable resource for sourcing information regarding the technologies chosen for review. The authors of the ANM Register recommend that the register is regularly updated, and this recommendation is reiterated here. 15 For example, EA Technology, Identification of Outline Solutions for the Connection and operation of Distributed Generation,

18 3.4 Other Projects of Interest from the ANM Register ENA Reports The Electricity Networks Association (ENA) has produced several Engineering Technical Reports related to the connection of DG and identified in the ANM Register, in particular: ETR 124 Guidelines for Actively Managing Power Flows Associated with the Connection of a Single Distributed Generation Plant ETR 126 Guidelines for Actively Managing Voltage Levels Associated with the Connection of a Single Distributed Generation Plant ETR 130 Application Guide for Assessing the Capacity of Networks Containing Distributed Generation ETR 131 Analysis Package for Assessing Generation Security Capability The first two reports in particular are designed to be planning guides for DNOs addressing an application for connection from DG which cannot easily be accommodated in the normal unconstrained manner. However, it is unclear whether they are being used, given that many of their recommendations are related to the technologies identified in this report which have not been widely implemented Dynamic Equipment Rating One potential means of increasing the amount of export from DG without upgrading lines that are currently operating at close to their thermal capacity is through the use of dynamic line ratings. This can ensure that the limits imposed on connected DG are reasonably linked to the real time conditions of the lines. Generally, safety margins are set so that ratings will not be exceeded even under the worst case conditions, resulting in capacity being available but unused. The Skegness Boston RPZ will encompass dynamic line rating using a device called the Power Donut2, from USi-Power to measure the actual sag of the lines and thus provide feed into calculations to determine what the additional line loading could be. The ANM Register also lists other condition monitoring technologies for transformers and cables Control Besides micro grid controllers, other methods have been proposed using, for example, various state estimation techniques, and some existing commercial control systems such as ENMAC can incorporate such functionality to provide similar levels of active voltage control as it is described in ETR DGFACTS The aim of the European research project known as DGFACTS was to research quality problems on the distribution networks and to develop FACTs devices suitable for solving these problems. The programme was designed to develop both stand alone (such as the D-STATCOM) FACTs devices as well as integrated devices. Integrated devices will expand the capability of standard inverter connected DG from merely meeting Distribution Code requirements at the point of connection to actively providing DNOs with power 12

19 quality support. DGFACTS resulted in a large body of literature describing the state of power quality on the distribution networks throughout Europe, as well as functional specifications for FACTS devices and for quality standards and regulations as well as for test procedures. It found that quality standards throughout Europe vary considerably, as do actual performances. 13

20 4 SELECTION OF TECHNOLOGIES FOR APPRAISAL The following technologies were identified from the literature review, and after consultation with the project team, as suitable for further study. In effect, technologies that are largely available now but for various reasons are not being widely used by the DNOs have been selected, rather than brand new technologies. 4.1 Primary Plant Inline Voltage Regulators (IVRs) Static VAr Compensators (SVCs and STATCOMs) Both of the above relate to voltage control, with other power quality and stability benefits from the use of the FACTs devices. 4.2 Secondary Plant Active Voltage Controllers (new and existing) with state estimation modules (not currently employed for ANM purposes) At least two micro-grid controllers are being developed in UK to specifically provide ANM of small sections of the distribution network where it is most needed. In addition, at least one major SCADA manufacturer has developed a module that can provide real time state estimation on the distribution network and is building upon this to add ANM control functions. Dynamic Line Rating 4.3 Rejected Technologies There are a number of other technologies being developed that were not selected for this study for reasons such as: They will not be available in the required timeframe (eg solid state tap changers) They have been designed to overcome a short-term problem (eg devices aimed at overcoming the reverse power limitations of existing, reactor based tap changers as such transformers are undergoing ongoing upgrade and replacement) They fall outside the scope of this project (eg protection based technologies) A judgement of the cost benefit analysis suggests they are less likely to be economically viable in the required timeframe than those chosen (eg some energy storage solutions 16 ) They are significant safety concerns (eg sequential switching for fault level limiting) The main issues for the technology are regulatory, commercial and contractual rather than technical (eg use of DG to provide reactive support and DSP) 16 For example, Assessing the feasibility of establishing power zones on Northern/Yorkshire Electricity, Econnect, 2006 and the Technology Report 14

21 5 TECHNOLOGY APPRAISAL ASSESSMENT METHODOLOGY The following questions were considered when assessing each of the technologies. 5.1 General Overview of the technology what problem is this technology designed to overcome and how does it achieve this? State of development is the technology likely to be commercially available within the next 5 years? 5.2 Technical Safety and environment does the equipment introduce any unacceptable safety or environmental risks? Is it failsafe? Are there adequate failsafe backup systems? What is the consequence of failure? Functionality what issue/opportunity is the technology designed to overcome/enhance? How well does the functionality of the technology meet its particular objective? How much benefit does the technology provide (quantified where possible)? Is the technology unnecessarily gold plated? What other advantages does this technology give to DNOs and other stakeholders? Technical barriers are there any particular technical barriers to the adoption of this technology? Specific communications and SCADA issues what speed of operation and bandwidth is required? What reliability is required? Can this be achieved using existing systems? Are there any issues with communication standards? Application engineering - How complex is the application engineering? How modular is it? How well has the software/logic been tested compared to the hardware platform? 5.3 Operational Impact on existing network how well does the technology integrate with existing systems, equipment, and operations (particularly with respect to safety and reliability)? Operational robustness what is the technology s availability, and on failure, how long to repair/replace compared to traditional solutions? How often does it need to be maintained? Design robustness how modular is the technology? Must each installation be significantly customised? Impact on operational staff what changes to operating and maintenance practices will be required? What additional training might be required? Legacy issues will the technology result in scattered bespoke solutions, each requiring considerable knowledge transfer as development staff leave? Impact on key operational measures eg CML, CI, etc 15

22 5.4 Planning Risk identification and analysis, including failure rates where that information is available. What are the consequences of failure? P2/6 requirements will the technology make it easier or harder to assess compliance than traditional solutions, such as installing new lines? What happens when the technology is not in service? Expected life of technology compared to traditional solutions Future proofing will the technology integrate well with likely future network architectures identified in Work Programme 1 Project 2 or will it impede their development? How adaptable is the technology to meet changing requirements? How difficult will new hardware or software upgrades be in the future? Integration with existing planning systems will training and new systems be required for planners and consultants? Notes on cost, where that information is available 5.5 Other Appraisal against the criteria of Engineering Recommendation G85 (regarding innovation in electrical distribution network systems), and thus suitability for funding from the Innovation Funding Initiative (IFI) and Registered Power Zone (RPZ) Ofgem incentive mechanisms. To be eligible for these programmes, the project must meet the following criteria 17 : Technical Development is the project of a technical nature and related to enhancing the technical performance of a DNO s network Degree of Innovation is the project sufficiently innovative? Is it an applied invention that has, so far as can be reasonably demonstrated, not previously been adopted by a UK DNO? Customer Value will sufficient value delivered to end consumers if the project is successful? Final commentary on any other issues that appear during the review. 17 From Engineering Recommendation G85, Innovation in Electrical Distribution Network Systems; A Good Practice Guide, ENA,

23 6 DETAILED ANALYSIS 6.1 Inline Voltage Regulators Overview Inline Voltage Regulators (IVRs) are effectively 1:1 ratio transformers with on load tap changers (OLTC). They are most frequently used by DNOs to boost the voltage at the end of long radial feeders (often with several spurs) that experiences substantial volt drop towards the end of the lines, and where this cannot be alleviated by boosting the voltage at the substation without causing the voltage for near in customers to exceed limits. However they also have potential to control the voltage on feeders containing DG 18, leaving the voltage on the rest of the system to be managed by the AVC at the main substation. Figure 1 below provides a generic example of a conventional use of an IVR. A radial feeder experiences increasing voltage drop with increasing distance from the substation. When an IVR is introduced, the voltage at the end of the feeder is restored. In Figure 2, DG connected at some distance from the substation causes the voltage to rise. When an IVR is connected, voltage near the DG is reduced. Figure 1: Conventional network, with and without an IVR 18 For example, as described in Optimisation of the Application of Sustainable Energy Systems, Chapter 4, Grid Connection of Wind and Solar Sources (1) Optimising Generation Levels, University of Western Sydney,

24 Figure 2: Network with DG, with and without an IVR The IVR is a well established technology, and uses both power and control components that have been used in the field for many years with several suppliers. The majority of the experience to date has been to use IVRs as a voltage booster, ie to increase voltage unidirectionally and often using fixed or seasonal tapping. Nonetheless, there examples around the world of the bi-directional use of IVR, including in South Africa, the United States, Australia, New Zealand, Greece 19 and one identified example in the UK. This latter was installed by Scottish Power on a trial basis in North Wales in relation to connecting DG. A considerable body of literature is available concerning IVRs, including datasheets from various manufacturers, which were reviewed for this report. The project in North Wales used a Cooper Power Systems 20 IVR. Other manufacturers identified include Siemens 21 and GE Energy 22. Each of these manufacturers offer single and three phase IVRs with the capabilities discussed in this report Technical Issues Safety and Environment Safety and environmental risks for IVR are similar to that for transformers and other oil cooled equipment, and revolve around the risk of fire, explosion or general oil release. Oil tanks are generally of sealed construction, however as with any OLTC, there is some risk associated with the moving parts of the tap changer. Such risks are managed using pressure relief devices, oil level gauges and oil sampling and temperature alarms 23. These alarm devices could be used to trip an upstream circuit breaker, thereby appearing to present no greater risk than any equivalent ground mounted or pole mounted transformer and less risk than the majority of transformers without such protection. 19 Report on Steady State and Dynamic Analysis of MicroGrids, MicroGrids Consortium, For example, the VR-32 model, accessed October For example the JFR model, accessed October For example, the VR-1 model, accessed October Quantified in manufacturers data sheets, such as those from Cooper Power Systems, Siemens, et al 18

25 Functionality If a connecting distributed generator is considered to present unacceptable risk of voltage rise on the local feeder even after adjusting local AVR settings, then the traditional solution might have been to construct a dedicated circuit from the substation, often at the primary rather than secondary voltage. Various previous DWG and DCDG reports have suggested a hierarchy of voltage control solutions depending on the extent and nature of the problem. For example, it might be possible to adequately control the voltage using the tap changers on the main transformers as the only controlled element, with various modification of the existing AVC schemes such as by using line drop compensation, cancellation CTs or others techniques to modify the measured variables or the control philosophy 24. If it is not possible to keep the voltage of supplied customers within range for all parts of the network using the transformer OLTCs (usually because the variance on different feeders is too wide, as is the classic case with DG), then IVRs might be considered. At this stage, the DNO would have several decisions to make to ensure that an appropriate balance is reached between adequately addressing the voltage issue and avoiding unnecessary cost and complexity. Typically, IVR provide around ±10 to15% voltage regulation using in the order of 32 steps. The actual benefit provided must be determined by system studies on a case by case basis; however the example in North Wales reportedly provided an increase in network capacity for generation connection on an 11 kv feeder from 600 kw to 2.3 MW in this particular instance, with significant avoided costs for a new line 9. System studies must determine on a case by case basis whether it will be appropriate to use an IVR in any given situation. In addition, consideration must be given to what control functions will be used and how much interface with other network devices and the DG will be required. Sample studies reviewed for this report show that an outage of a single connected DG might be a concern. If the IVR is on a low tap to correct a voltage rise problem at a time of low load and high generation, and then that DG trips, it is possible that customers downstream of the IVR will experience low voltage until the IVR can tap back up to restore the voltage. This might take up to 15 seconds, although manufacturers advertise faster tap changing times than this 25. Engineering Recommendation P28 ( Planning limits for voltage fluctuations ) will apply in such circumstances. Studies will be needed to determine whether the settings for the IVR can be selected to manage this issue. It should be noted that in some cases, voltage problems on distribution networks are accompanied by a lack of thermal capacity. The IVR usually does not provide any assistance with thermal limitations, or might worsen existing issues as upstream currents are increased. Given that the majority of UK distribution circuits have been optimised in terms of distributing voltage and length, appropriate locations for IVR installations are likely to be limited to long rural feeders with connected DG. 24 Methods to Accommodate Embedded Generation Without Degrading Network Voltage Regulation, EA Technology, Datasheets from Cooper Power Systems state that the Cooper Quik-Drive Tap Changer can achieve 32 tap steps in 9 seconds. 19

26 System Modelling One of the main barriers to broader adoption of this technology would appear to be a lack of experience with using an IVR in conjunction with DG. In the UK, this is compounded by a lack of familiarity using IVRs in their more traditional roles as voltage boosters. Power system modelling software used by DNOs and their consultants might not have standard models or data for IVRs or might not have the knowledge and experience to use them. The Scottish Power example in North Wales required some novel system modelling from first principles, and time and cost pressures might make such effort appear uneconomic for some projects. This is likely to be the case with most if not all new ANM technologies. The short time frame in which a DNO must respond to a connection application from a DG or other customer means that currently new technologies are probably not being considered. Therefore, requisite changes to the DNO s planning practices must be made prior to the decision to implement a technology in a particular situation. Communication The IVR might be suitable to be a standalone device in the network, or it might be necessary or desirable to coordinate control of the IVR with that of the main substation OLTC or the DG controller. Some form of remote visibility and control is likely to be desirable so that operators can take an IVR into account when reconfiguring the network. It might also be necessary to consider the effect of the operation of the IVR on the AVC at the substation. If it is considered necessary or desirable to coordinate voltage control between the IVR and other system elements, then some form of active voltage controller might be required. Active voltage controllers are discussed further in this report Operational Issues An IVR should theoretically integrate well into the existing network, being fundamentally similar to existing components. Standard protection design, equipment and maintenance practices should be able to be used. Similarly, the principles behind the control of the device are not dissimilar to those of the AVC on the step-down/step-up transformers. Most manufacturers offer training courses with their devices, at most a day s training might be required for commissioning and maintenance personnel. Before introducing a new device into the network, a spares and maintenance strategy will need to be determined. Faults on an IVR are infrequent but may result in replacement. The use of the bypass switch should help minimise supply impacts, and normal oil testing and other preventative maintenance measures should be readily incorporated into existing plans. Operational staff will have to understand the role that the IVR plays in voltage regulation on the network. The biggest change to DNO practices is likely to be during the initial studies to determine the tapping range and control parameters, as it may represent a somewhat novel method of managing voltage regulation on the network Planning Issues Reliability and Consequences of Failure The likelihood of failure of an IVR is comparable to that of a modern transformer, making it one of the more reliable components of a power distribution system. As with a 20

27 transformer, the consequence of failure must be considered in terms of maintaining compliance with the P2/6 security standard. This will be dependent on individual circumstances, such as the surrounding networks transfer capability, the connected load and so on. In general, the design of the installation should ensure that no adverse effect is made on CMLs and CIs. If restoration of supply in abnormal circumstances would require adjustment of settings (at the transformer or the IVR) then this could have an adverse impact on CMLs. Most IVRs can be fitted with an optional bypass switch that operates without interrupting supply. In the traditional voltage boost case where an IVR has been used to correct a volt drop problem, bypassing the IVR at peak load times might leave downstream customers with low voltages. However, in the situation being considered here where the prime purpose of the IVR is to decrease the voltage at times of low load, high generation, bypassing the IVR might necessitate constraining the downstream DG. Given the low probability of bypass being required due to IVR failure and the ability to schedule maintenance bypasses to cause minimal disruption such a constraint is likely to be acceptable to a DG developer who has avoided significant capital outlay through the use of the IVR. At least two DNOs in New Zealand 26 assume a 55 year lifetime for IVRs. Adaptability The adaptability of the IVR will be limited to its tapping range. If the IVR just manages to keep voltages within limits for the connection of one DG, then it is unlikely to cope with further DG unless accompanied by sufficient growth in minimum loads near the DG. In addition, Figure 2 shows how sensitive the network voltages are to the position of the IVR. In the same way that customers close in to the primary substation might experience high voltages, so customers close to the IVR might experience high or low voltages (on the primary or secondary side). System scenarios must be studied to ensure that the use of the IVR and its physical position are not invalidated following foreseeable changes to the network to avoid the IVR becoming a stranded asset or having to be relocated. Sample studies reviewed for this report show that in some cases, selection of the optimum settings will be quite sensitive to network configuration. Using an IVR with some form of active voltage controller should mitigate this issue. Costs Costs for an IVR will obviously vary depending on voltage level and rating, and whether a 2-phase (can) open delta or a 3-phase configuration is used, but in general it is reasonable to expect that an 11 kv IVR could be installed for considerably less than the cost of a new line circuit. An IVR is essentially a 1:1 autotransformer and depending on the buck/boost tapping range, the cost of an IVR could typically be about half the cost of a two winding transformer of the same rating. The 11 kv single phase voltage regulator used in the North Wales example would typically cost in the region of 30, Optimal Deprival Valuation of the System Fixed Assets for Scanpower 2004 and Unison Solutions for the Connection and Operation of Distributed Generation, EA Technology, 2003 cost of an IVR quoted in this report of 20k was escalated by approximately 10% pa, which results in a cost comparable with those quoted for projects in South Africa, Australia and the USA 21

28 6.1.5 Other Issues A project to install an IVR might reasonably be considered to enhance the technical development of the network and thus meet this requirement as given in G85. However, the innovation criteria require that the technology has not been used previously by a UK DNO. An IVR has already been installed in the UK by at least one UK DNO (Scottish Power in North Wales), and so a similar project might not meet the ER G85 innovation criteria without incorporating something incrementally different. An example might be to combine operation of the IVR with an active voltage controller. As the installation of the IVR would be intended to reduce capital costs attributed to the DG, who could then presumably deliver this benefit to end consumers, the consumer value criteria should be able to be met. Similarly, it might be difficult to justify the creation of an RPZ on the basis of installing an IVR alone to connect DG, although it could form part of a larger scheme. For example, use of the DG that was connected via an IVR to enhance supply continuity and quality might qualify as an RPZ. 6.2 Synchronous Compensators: SVCs and STATCOMs Overview A STATCOM is a device that is capable of producing or absorbing reactive power using a combination of capacitors, reactors and power electronic switches. There are a number of uses for STATCOM devices including power factor correction, wind energy voltage stabilisation, and harmonic filtering. Shunt power electronics devices such as SVCs and STATCOMs have traditionally found application as transmission devices with little application at distribution levels. They are in fact still relatively rare at the transmission level, although they do have a long history of use. However, around the world there are also a few examples of the use of these devices at the distribution level, and one of the factors driving increased interest are the potential voltage and power flow problems experienced due to DG. They have also been used for disturbing loads (eg arc furnaces) to ensure power quality standards at the connection point are achieved (typically installed by the customer rather than the DNO) and for very sensitive loads (eg semi-conductor manufacturers). The D-VAr, a small STATCOM device, has been used on Orkney Island for some time and is critical to maintaining the stability of the power system. Within its operating range, a STATCOM will maintain excellent power quality and stability through voltage regulation, harmonic cancellation, power factor correction, removal of voltage flicker and dynamic damping. STATCOMs are currently being installed on some windfarms to ensure grid code compliance regarding fault ride through capability, up and down ramp rate, reactive support and power quality requirements. SVCs are an older technology with similar properties, but with less flexibility than a STATCOM. SVCs use thyristor technology and STATCOMs use IGBT technology. Besides the body of literature available on this subject, Areva responded to a questionnaire regarding their development of a D-STATCOM product for distribution networks, providing much of the information presented in this report. This product is in a stage of late development, and is expected to be commercially available soon. It will have a ±10 MVAr range, which is a range commonly found on recent windfarm installations. 22

29 The D-VAR is another small scale STATCOM product developed by American Superconductors which has been implemented in a number of sites in the USA within the last decade, usually with an 8 MVAr range. ABB market a distribution SVC product (MINICOMP ) with ranges from ±0.3 MVAr to ±20MVAr Technical Safety and Environment SVCs and STATCOMs generally consist of a step-down transformer, a coupling reactor or switched capacitor bank/harmonic filter, the power electronics and control and cooling equipment. As with an IVR, the major safety and environmental risks relate to the oil filled equipment, and these risks are well known and managed within the electricity industry. Standard alarm and protection measures must be taken as well as providing appropriate oil bunding. In addition, any water cooling system containing ethylene glycol to prevent freezing during winter conditions will require containment. The devices will normally be supplied with appropriate containment systems. Access to the power electronics area must be prevented during operation (for example, using standard electrical and mechanical interlocks). Functionality STATCOMs and SVCs have long been recognised as being capable of significantly improving power quality and STATCOMs have many features to solve stability, voltage and other quality problems for DNOs. They respond very quickly to events on the network. However, the power electronics make these devices relatively expensive. Therefore, their functionality and performance must be matched with a system need to ensure economic justification. Increasing levels of DG might provide such a need in some areas of the network, particularly where installing new lines or cables will be very difficult or expensive and where other solutions such as IVRs cannot provide adequate control. There might also be some advantage in combining the ability of a STATCOM to ensure distribution code compliance for wind farms with broader network uses. This would require collaboration on behalf of the DNO and the DG developer. As with all such voltage control devices, system studies will be required to determine the optimum location and ratings and setpoints of the unit. Communications SVCs and STATCOMs can operate as standalone devices or can be integrated into a broader area control system. In each case some communication will be required, as even standalone devices will require some level of alarming. Areva expect that most standard forms of communication could be used Operational Although relatively complex pieces of equipment in themselves, delivered SVCs and STATCOMs should be capable of being treated as a black box to DNO designers and operators. Planners will need to understand how the device functions to take it into account when modelling the system. 23

30 Some form of training for maintenance personnel is likely to be necessary so that parts such as the various control cards (eg power supplies, processors etc), the cooling system (water pumps, valves etc) or semiconductor devices can be removed and replaced as necessary. One reported outage of a D-VAR in the USA was due to an extended outage exceeding the unit s auxiliary battery supply. Being a modular design, if the DNO carried spares then it is likely failed parts could be replaced in a relatively short time. The D-STATCOM will require a short inspection each year primarily for the water cooling system with a major maintenance check once every three years. The D-VAr has an air cooled system which will also require some maintenance Planning Reliability and Consequences of Failure STATCOMs and SVCs are shunt devices, and so failure to operate will result in a failure to provide quality of supply support but no other consequences. The seriousness of complete failure to operate will depend on the situation. If being used specifically to support the connection of DG, then that DG could be turned down to a predetermined safe level as a failsafe measure (for example, on loss of communications to the device). One D-VAR project used to support voltages in the USA and to defer substantial line upgrades had a reported reliability of 99.66% for its first two years of operation following its installation in Future Proofing The D-STATCOM device is being designed as a mobile plug-in device that can readily be moved from one substation to another in case of changing system needs. The D- VAR is similarly mobile. Provided substations have the physical space and a spare circuit breaker, a mobile STATCOM should allow some future proofing of investment. In addition, its modular nature will provide scalability should greater ratings be required in the future. The D-STATCOM is expected to have a standard 30 year lifetime, making it compatible with other equipment on the network. Cost Worldwide demand for SVCs and STATCOMs has been anecdotally lower than expected by manufacturers, which combined with increased manufacture of the power electronic components for wind turbines is causing prices to decrease somewhat. Actual pricing of the D-STATCOM and similar products was considered commercially sensitive and was not made available for inclusion in this report. At the transmission level, the relationship between the price and the rating of SVCs is normally non-linear. An SVC with a range of 200 MVAr is likely to be roughly twice as expensive (in the order of up to 10m plus associated installation costs) as one with a range of 50 MVAr (rather than 4 times as expensive). How this will translate to the distribution level is uncertain at this stage, however other sources suggest a cost in the 28 STATCOM postpones the Need for 161 kv line, Ian Grant, Tennessee Valley Authority,

31 range of 1m for 10 MVAr. Areva are attempting to reduce costs for the D-STATCOM product by designing it to be an off the shelf, black box solution with a fixed rating. As with the IVRs, there are also likely to be training costs associated with upgrading planning methodologies and system modelling tools to accurately predict STATCOM behaviour on the network. Other It is understood that no UK DNO has installed a distribution STATCOM or SVC specifically in conjunction with allowing greater DG penetration onto the network, and therefore it is highly likely that such a project would qualify for both the IFI and RPZ schemes. The Orkney D-VAR was largely installed due to load issues, providing reactive support when there was little generation. Although several windfarms have installed STATCOMs, using devices such as the D-STATCOM on the network with DG is likely to be considered sufficiently novel to warrant qualification. 6.3 Voltage Control by Active Controllers Overview Traditional SCADA systems take basic status and analogue information and generate alarms, undertake logic sequences and allow remote circuit breaker operation (currently this is likely to be at primary substation level and above). At some point, if the goals of ANM are to be achieved, it seems likely that far greater levels of control, automation and data acquisition will be needed in the MV network below primary substation level. The question of what level is or will be needed is largely beyond the scope of this report, however two different scales of active voltage controllers (as referred to in ER ) will be considered. The first is a micro-grid controller, aimed at niche pockets of the network containing DG and effectively acting as distributed intelligence controllers. The second is aimed at providing a broader level of functionality that can be gradually implemented over the whole network as an expansion of existing SCADA systems. Currently, most AVCs controlling transformer OLTCs operate as stand alone control loops using static setpoints calculated in advance and then set and largely left alone, although most DNOs can set setpoints remotely from SCADA 5, at least at the primary substation level. This system of voltage control (with or without the other various modifications considered in ETR 126 such as cancellation CTs), might not be sufficient when a DG is connected into the network under all normal load and generation scenarios as discussed above in relation to IVRs. An active voltage controller takes a certain amount of real time measured information, a model of the network and some basic load profile data and then estimates load flows and voltages out on the network. With this information, it will dynamically adjust the setpoint of the transformer (or transformers) AVC or control other IEDs as appropriate, possibly including the DG, to keep the voltage within limits at all points in the area impacted by the controlled devices. The operation of a voltage controller is described more fully in ETR Engineering Technical Report Guidelines for Actively Managing Voltage Levels Associated with the Connection of a Single Distributed Generation Plant, Energy Networks Association,

32 Two manufacturers in Great Britain are currently developing micro-grid controllers, Econnect with the GenAVC project and ABB with the AuRA-NMS project. The GenAVC project, which is now commercially available, has been largely funded by the DTI and is a key part of the Martham Primary RPZ. The AuRA-NMS is being developed in conjunction with IFI funding and is still in development. A considerable body of literature is available regarding the GenAVC and ABB was approached for further information and responded to a questionnaire. Information from both sources is presented here. Both are designed to be installed in the substations and control an area of the network (a micro-grid ). The AuRA-NMS will also perform dynamic system analysis, building on load flow analysis capabilities. Neither product has reached full commercial mode as yet, but both are currently undergoing extensive pilot trials and could be reasonably expected to be available within the 5 year timeframe considered in this report. The ENMAC DMS/SCADA system is widely used amongst DNOs in the UK, and is a part of the Skegness RPZ. The manufacturers, GE Energy, have developed a Distribution Power Analysis (DPA) module to perform online power system analysis and state estimation which interfaces between the existing SCADA dataset of real values and network data and an analysis engine. GE Energy responded to a questionnaire regarding this module, as well as more generally regarding the capabilities of ENMAC and ANM modules under development. This information has been also used for this report, and it is assumed that other control systems have or could have similar capability within the timeframe considered for this report. The DPA module has been extensively tested over several years, in particular with one DNO in Australia; however it is currently missing the final step of active voltage control, which is the functionality of actively managing the setpoints. GE Energy is developing that end to end functionality in an ANM module to interact with the existing systems. This system could also reasonably be expected to be available within 5 years. In both cases, standard state estimation methods have been used, as they have been for many years at a transmission level, to estimate analogue values such as feeder voltages that are not currently measured in the field. The micro-grid controllers have been developed specifically for the active voltage control function, whereas the DPA module is used by operators for a range of operational activities, including predicting the outcome of switching procedures Technical Safety and Environment Beyond ensuring that the individual components of the controllers meet appropriate safety standards, the key concern will be that the controller causes voltages at the customers terminals to exceed limits and cause equipment damage. Unlike, for example, oil, gas, and chemical installations and thermal power stations, most control systems for electricity networks tend to be based on fairly low cost technologies and design principles and are rarely fully duplicated (excluding some protection systems). Therefore, control logic must be designed to be failsafe to ensure that when any part of the control and communication systems fails, an unsafe situation will not occur. Both the micro-grid controllers and the central control modules have this capability. 26

33 Accuracy of the active voltage control system will largely depend on the accuracy of measuring and controlled devices, such as transducers and tap changers. This is therefore not different in principle from existing forms of voltage control at the primary substation and should be considered in the same way for each new installation. Failure of the unit to operate as expected must also be considered. It is possible that the unit will drive the voltage in the wrong direction and exceed limits, for example because of an incorrect reading or unexpected network configuration. However, these risks already exist on the network, in particular during manual operations and it could be argued that the micro-grid controllers with their state estimation abilities reduce these risks overall. Functionality In general, studies 30 and trials 31 have shown that where voltage rise was a limiting factor for connecting DG to a feeder, active controllers can roughly double the amount of DG that can be connected to that part of the network without substantial reinforcement. Voltage problems on 11 kv networks are likely to be particularly relevant as at these levels transformer taps are often fixed. Therefore, the expected benefit from an active voltage controller for a particular area might be in the order of 2-4 MW per feeder of additional generation. The range of the controller will be limited by the extent to which voltages on different feeders differ. If the controlled devices (usually the OLTCs at the primary substations) cannot physically be set to keep the voltage of feeders without DG within limits at the same time as the voltage on feeders with DG, then the active voltage controller solution will not be sufficient. Some other form of voltage regulator, such as an IVR, capacitor banks or an SVC or STATCOM might need to be implemented, either as a stand alone device or to be controlled in conjunction with the other devices by the controller. Alternatively, on the occasions when the voltage rise was too great, DG might need to be constrained by the controller. Studies would be needed on a case by case basis to determine likely scenarios. As with the previous two ANM technologies discussed, these studies are likely to require a change in planning practices by the DNO, which should be easily implemented. Centralised Control versus Distributed Control The question of whether to employ devolved controllers at the substation level versus using centralised controllers depends on a number of factors. Those discussed below include: Ease of maintenance following system changes Standardisation of hardware and logic Replication of hardware and logic Speed of deployment Need for and speed and reliability of communications 30 Integration of Operation of Embedded Generation and Distribution Networks, UMIST, Econnect, Active Local Distribution Network Management for Embedded Generation, Econnect,

34 Network changes may need to be configured into the controller, presenting an ongoing maintenance challenge and also potentially requiring additional expertise for operations and maintenance personnel. This could be a particular problem at the 11 kv voltage level where changes to the network can be frequent and options for reconfiguring the network to restore supply following a fault are numerous. Modifications might be more manageable at the central SCADA level than at the distributed controller level, as changes to network configuration must be captured in network diagrams regardless of the presence of control. One of the goals of the Aura-NMS project is to provide a repeatable, non-complex distributed solution for this issue 32, however the project development is not yet far enough advanced to accurately assess whether this will be achieved. Another consideration is amount of replication required for each new micro-grid. In both the centralised and distributed cases, the necessary measurement and control devices and the communications to the nearest data collection point (usually envisaged to be at the primary substation) will be needed. In addition, all of the standalone micro-grid controller hardware must be replicated, whereas the centralised controller might only need, for example, an additional card on an existing RTU to feed data back to the control room. However, where existing SCADA systems do not have the capabilities to easily incorporate active voltage control, localised, specialist controllers might be a more appropriate means of rapidly deploying active voltage control functionality. Similarly, if a DNO expects only a few micro-grids to be required based on the location and numbers of DG and does not see any significant benefits from the broader scale implementation of state estimation techniques, then localised controllers might be appropriate. In this case though, there is the risk of creating legacy issues, where a few numbers of unique devices, each highly customised and non-standard, are on the network needing specific knowledge transfer as personnel change. Installation of a micro-grid controller at secondary or low voltage substations, where DNOs typically do not have any visibility of system voltages, could remove the need to install or upgrade communications to the SCADA following connection of DG. This assumes that the secondary substation transformers have OLTCs, without which the active controller has nothing to control, and this is frequently not the case. It is likely that the normal status points and probably some information from the DG will still be required by the operator. Using a centralised controller will have some advantages in ensuring that all of the system data is readily available in a single place, so that asset maintenance, outage planning, system planning, fault level analysis, fault detection, trending and other functions can use a single, centralised data source. In addition, updating of the application software and hardware as well as the network configuration should be simpler. Balanced against this is the faster control possible with a local, rather than remote controller. Considering the various paths currently used to communicate between primary substation RTUs and the SCADA (described fully in reference 5), a complete control loop might take up to 15 seconds. This, coupled with the response time of the OLTC might be too slow to maintain voltages within limits, and would have to be considered on a case by case basis. 32 Innovation Funding Incentive Annual Report, Scottish Power,

35 For example, this might not be a problem for most steady state conditions, as load generally changes slowly and, in the case of wind generation, maximum wind generation variation is unlikely to be more than 10% 33 in the 15 second timeframe. Following a system disturbance, particularly a generation trip, there might be a need to rapidly change voltage settings to prevent prolonged temporary overvoltages on the network. However in general, there should be no need for a faster control loop because of the speed of the controlled devices. If there is a need for faster response times, upgrading the communications link between the primary substations and the central SCADA system might be the solution where this could be economically justified. One of the key considerations with regards to communication is reliability. If the controller is critical to maintaining voltages and the controller is located remotely, then the communications to the controller will be critical. The system must already be failsafe in case of failure of the actual controller or other elements of the control loop, for example by causing any connected DG to go to a predetermined output in case of loss of communications to the controller. However, the more unreliable communication links between the controller and controlled and measuring devices that are added, the more likely triggering the failsafe position becomes Operational In each case considered, hardware and communication systems appear to use standard, mature technologies, and should integrate well with existing systems. The main design and maintenance concern, as stated above, will be the ease of updating the network models and other elements of the controller following changes to the configuration of the network. Standard logic and interfaces are needed to minimise customisation requirements at each site. A detailed examination of the installation requirements for each device would be required before being able to assess this further. Provided due care is given to the setup of the controller, its failure should not cause any negative impact on CML and CI measures (for example, on tap changer failure where DG setpoints reverted to safe values). Rather, the controllers should offer further opportunities for improving CML in particular. CML was possibly a key driver for the original introduction and expansion of SCADA in some of the Great Britain networks, as it provided a means to reduce the time taken to identify fault locations. In addition, some DNOs have experienced considerable CML improvements using automated post-fault feeder restoration 34, which could be added functionality of an active voltage controller Planning Reliability and Consequences of Failure The main consequence of a controller failing to operate as expected is likely to be a voltage excursion one or more parts of the network. This might be caused in a number of ways, such as: Incorrect network data being input into the controller model 33 Based on the experience of SKM s wind generation group 34 For example, EDF undertook a project to automate 1700 feeders with considerable improvements in CML Electricity Distribution Cost Review 2004/05, Office of Gas and Electricity Markets,

36 Insufficient feedback from measured values Some novel feature of the network (such as a new FACTs type device or the DG) has not been correctly modelled in the controller Some unexpected event or network configuration has occurred that the controller is unequipped to cater for In essence, these causes of failure are not dissimilar to the types of problems that might occur with any system modelling of the network, for example to determine where investment is required, to develop DG constraints for contractual arrangements or simply to determine the original setpoint for an AVC. One benefit of the active controller is that when the problem is found (preferably during commissioning tests), the solution is likely to be easily implemented. Another is that while the same level of conservatism could be built into the active voltage controller as that used now in system modelling, the controller has a feedback mechanism and therefore can be tuned to operate the network closer to voltage limits with greater confidence. Commissioning of such a system, like any control function, will have to be carefully considered and comprehensively carried out. Creation of all likely network conditions for testing might be difficult, as with any network equipment. For this reason, the GenAVC is undergoing extensive trials in two sites, connected at first in open loop mode with control outputs carefully monitored. Initial testing of the DPA module of ENMAC at an Australian site was similarly carried out over a 12 month period in open loop mode. Such extensive testing is not likely to be commercially feasible if these controllers are to become standard practice, and therefore the extent of the difference in control logic between the project requirements and the extensively tested version of software must be considered on a case by case basis. GE Energy report an initial accuracy of 90% of the DPA module estimated network values when compared against directly measured values. This accuracy was achieved despite the state estimation algorithm being supplied only with single load values collected quarterly from secondary substations during inspections. After a period of monitoring and loop tuning by control room operators, the accuracy was considerably improved. Econnect report that GenAVC has operated for considerable periods in open loop mode showing that correct control actions would have been taken in closed loop mode. Therefore, in both cases it can be assumed that the state estimation functionality will provide operators with considerably more information than they current have access to. Cost The main benefit of installing an active voltage controller in a section of the network with connected DG will be to avoid large capital costs (usually attributed to the DG developer as part of the connection costs) of, for example new circuits at higher voltages. When comparing the capital costs in such a case, the controller option is likely to be substantially cheaper. However, the first such arrangement each DNO installs is likely to involve extra internal costs in adjusting to a new way of managing voltage control, and will require personnel to step out of the normal roles in order to implement these changes. A broader change to the main SCADA system will require additional training and participation by control room staff. 30

37 6.3.5 Other To qualify for IFI funding for an active voltage controller based on the GenAVC or AuRA- NMS system might be difficult unless the DNO could prove that the application domain or operating context is new or unexplored. This is possibly the reason that only one of the GenAVC trial sites was registered as an RPZ. However, the rules for the IFI actively encourage collaboration between DNOs, and so it is theoretically possible that a DNO not currently involved in AuRA-NMS might join the project. Another means of qualifying for either IFI or RPZ using GenAVC might be to incorporate the controller with a piece of primary plant with which it had not previously been trialled, such as an IVR or a FACTs device. As active voltage controllers for distribution networks are not a fully established technology, and each new manufacturer is likely to propose a somewhat different control algorithm or methodology at this stage, any other controller should qualify. This should include extension of the capability of a DNO s existing SCADA system to provide such functionality. Such a project would be similar to the EDF IFI project to incorporate state estimation into its overall network control. 6.4 Dynamic Line Rating Overview Ratings of power circuits vary according to a number of factors, most noticeably ambient temperature for transformers and overhead lines and burial conditions for underground cables. Traditionally, planners and designers have assumed worst case conditions when determining the capacity of the network to set protection, judge when upgrades are required, curtail generation and generally operate the network. However, the worst case conditions statistically rarely occur, and so for the majority of the time the operating and design limits of the network are less than the actual limit. The purpose of dynamic line rating is to operate the network at its actual, real time thermal rating and thus use the full capacity of an overhead line rather than an artificially constrained capacity and thereby avoid capital investment to uprate the circuit or unnecessary constraints on DG. This is particularly relevant to wind generation, as maximum power output from a wind generator is naturally coincident with maximum wind speed, and hence with potential cooling effects of the wind on nearby line conductors. The components of a dynamic rating system can include: Some form of direct measurement of line parameters Examples include measurement of the conductor temperature by embedded thermocouples, line sag using cameras, theodolites or inclinometers, conductor tension using load cells Measurement of local weather conditions using a standard weather station. Communication of these measurements to a controller 31

38 This might be via fibre optic cable run with the line or as OPGW or fibre wrap (which can be retrofitted to existing earth or power conductors), GPRS, UHF/VHF radio, microwave. Logic to determine what action should be taken given the measured value There are two weather related calculation methods 35, the Weather Model and the Temperature Model, provided in IEE Standard for Calculating the Current- Temperature Relationship of Bare Overhead Wires. Therefore, the logic sequence could use these methods to determine the real time maximum current rating of the conductor, and then take action to ensure that current flow is not exceeded. Alternatively, the logic or control loop could compare the measured value such as conductor sag or tension against a setpoint representing maximum allowable sag or tension and take action on that basis. Communication of an action request to a controlled variable, most likely to DG in the form of an instruction to curtail or relief of a constraint Verification that the action has kept the conductor within its determined limits Possible dynamic modification of protection systems to ensure grading with the dynamic rating system. Although several other systems using thermocouple and load cell measurement have been in use for some time, including the Kema 36 Dynamic Current Rating Optimisation, the Power Donut is being used by E.ON in the Skegness RPZ, and also by EDF. It has been the subject of numerous papers and studies and does appear to offer a unique solution to some of the problems with dynamic ratings raised in this report, and so shall be used here as a specific case to represent the generic class of dynamic rating devices. The Power Donut also provides a useful study base as it incorporates conductor tension, angle of inclination (which can be fed into a catenary calculation to give the mid span height), temperature and current measurements. In addition, dynamic rating systems based on weather measurements were considered. Scottish Power in collaboration with others is currently investigating thermal modelling with the goal of producing an active thermal controller using weather data combined with direct measurement of equipment parameters Technical Safety and Environment One of the key concerns with the dynamic rating principle is that if the process used to calculate the actual rating errs or fails in some way, then the actual rating could be exceeded causing possible equipment failure risks to safety and the environment. Failure or miscalculation will be a concern in cases where overcurrent protection, which is normally set to detect faults rather than overloads, will not activate before ground safety clearances of an overhead line are breached through excessive sag. In this case, some changes to the protection scheme might be required, or duplicated dynamic line conductor 35 Prospects for Dynamic Transmission Circuit Ratings, K. E. Holbert, G. T. Heydt, Arizona State University 36 KEMA, 32

39 rating systems based on different principles could be used to ensure increased confidence. Multiple measurement points will also decrease the chance of incorrect measurements or measurements remote from the sagging line leading to a breach of ground safety clearances. Failure or error could also be of significant (safety, rather than operational) concern when protection settings are being changed to achieve differentiation between the dynamically calculated maximum current and the overcurrent alarm and trip levels. For example, to achieve this grading it might be necessary to use summer and winter ratings on overcurrent protection settings (any form of unit protection scheme should be unaffected). Most modern protection relays in operation by DNOs have this capability 5, and these relays will already be communicating with the main SCADA systems in some fashion, although possibly only through aggregated alarms. Functionality The potential advantages of dynamic ratings for underground cables are limited, as burial conditions are static. Therefore, to gain advantage from dynamic rating on a particular circuit, any portion of the circuit that is constructed overhead must be the limiting factor on that circuit. Similarly, to gain maximum benefit on an individual circuit, the circuit must currently or be predicted to shortly exceed its conservative rating. When these conditions are met, then use of dynamic ratings to increase thermal capacity on a line might reasonably be considered. Whilst a significant proportion of the Great Britain distribution network is underground, the planning and cost barriers to erecting duplicate lines for those circuits that are overhead are considerable. The modelling done for the Skegness RPZ dynamic line rating scheme suggests that that scheme might see a potential doubling of thermal capacity at the highest wind speeds, allowing an increase of DG output on the line of up to 600 A onto the line in question without capital upgrades. Assuming that the modelling of the relationship between the wind cooling effect, ambient temperature and line capacity is correct, then the main variable in this system with regards to quantified benefit will relate to the coincidence of high wind speeds at the wind farm and high wind speeds perpendicular to the line. If the line is physically removed from the wind farm, or in a valley (and modern planning requirements often dictate least visible line routes) or behind some other obstacle to the cooling effect of the wind, then this benefit might be diminished. Location of Measurement Temperature and wind effects can be very localised, and the weather experienced by one span can vary to that experienced the next. A further consideration will be whether the same conductor is used over the entire circuit length. Each type of conductor will have different properties and will respond differently to changing weather conditions. Therefore, not only might a single span be the effective bottleneck on the rating of the entire line, but the particular span might change within a period of time. Therefore, one technical risk to be carefully managed with dynamic ratings relates to the position of the measurement devices. Communications One of the key components regarding dynamic rating systems will be the communications from the measurement system to the controller and from the controller to the controlled 33

40 device (and then verification that the controlled device has taken the correct action). Considering the variables that the dynamic rating system is based on (that is weather variables such as wind speed, direction and ambient temperature), a complete cycle time of a few minutes would seem a reasonable expectation. Specifying a faster time might be unnecessarily onerous. The speed of response of conductor sag to changes in weather conditions is discussed further below. The Power Donut system uses standard GPRS mobile phone technology. A central controller is fitted with a standard SIM card and given a fixed IP address and each unit in the network can be set to transmit its information to that IP address. Clearly the reliability of this system is reliant not just on the components in the measuring device and the server but also on the mobile network provider. The manufacturer quotes reliability of levels of over 99.9% during the longest trial of this version of the communications platform at an Italian site since One of the advantages of this system is that no additional infrastructure is required, particularly in Great Britain which has extensive GPRS coverage. This coverage also means that for many sites, the line being measured will be within range of more than one base station tower, providing redundant paths to the internet and hence to the server. This would have to be confirmed on a case by case basis. Data transfer by GPRS is a well proven technology and should be very simple to install and operate. Although not as fast as, for example, a direct fibre optic or microwave link, for this application update times should be perfectly acceptable. The available bandwidth should be more than sufficient given that the current GPRS network in Great Britain has been designed with significant data transfer capability. Communications will also be required from the controller to the DG. It is likely that two levels of communication will be required, one to send a curtailment (or relieve a curtailment) instruction and verify that action has been taken and the second to send a trip signal if the DG has failed to act as expected, thus pre-empting any protection trips to avoid disruption to other customers. The specification for the first application will be low speed, low bandwidth but preferably good reliability to avoid unnecessary curtailment (this could be decided by commercial arrangements with the DG developer). For the second application, moderate speed (assuming the remainder of the line measurement, decision making, communication and verification steps have been completed within the time for the line to respond to changing conditions) and excellent reliability will be required. Previous reports into existing DNO communication systems suggest that both specifications should be relatively easily achieved using existing equipment. Calculation of Dynamic Rating The relationship between conductor temperature, line sag and current rating is not straightforward. Systems based on weather station data seem particularly vulnerable to error. The IEEE standard states that wind blowing perpendicular to a line provides a 60% greater convection cooling effect than wind blowing parallel. Perpendicular wind speed has a greater impact on conductor temperature than any other parameter (eg, solar radiance). That such a large range of cooling can occur due to something as variable as wind direction implies that the calculations must either be very accurate, and based on accurate and comprehensive weather data measurements, or else 34

41 incorporate considerable safety margins. Indeed, studies 35 have shown that the accuracy of the calculated capacity is particularly sensitive to the accuracy of the measured wind speed and direction. Measurements have shown up to a 30 C temperature rise within several minutes of a sudden wind speed drop or change of wind direction 37. It might be possible to use just local weather data if dynamic rating is being used for a region of interconnected lines and wind generators. However, the individual line capacity benefit would be reduced through having to incorporate safety margins to allow for local wind speed and direction variability. The key parameter with regards to line rating is generally line sag rather than temperature, as ground clearances are likely to be breached before the conductor fails through excess temperature. Therefore, a system based on measured sag could bypass most forms of mathematical modelling of the interaction between line rating and weather and simply ensure that the sag does not exceed a setpoint based on clearance to ground. The Power Donut derives sag from measured inclination and fixed parameters such as conductor mass. Trials performed have also shown good correlation between conductor temperature and sag, so that temperature could also be used as the measured parameter with minimal indirect calculation required. The logical sequences and communications installed for one dynamic rating system should be relatively simple to replicate so that increasing numbers of lines with these systems would not cause increasing complexity by themselves. That complexity is more likely to arise from the interactions with the DG. In general, it would appear technically preferable to base the dynamic line rating on direct measurement of the conductor rather than on estimation performed from weather measurements. Alternatively, if a large region or a long line was being dynamically rated, weather measurements could be used with a few strategically placed direct measurement devices providing data backup and verification. The Skegness RPZ is using the latter model, with line rating data supplied to the ENMAC control system which then dynamically adjusts alarm setpoints and other relevant parameters. The results of this arrangement, including how well the measurements taken of conductor temperature and tension and inclination correlate with ratings based on weather station data will be of interest. Other Advantages A device such as the Power Donut provides a large amount of data, including current and voltage waveforms. It is conceivable that this information could be used for event analysis and in other ways Operational The primary maintenance related impact of dynamic line ratings will be related to the measurement systems. The Power Donut can be fitted or removed live using supplied hot sticks 38, and weather stations local to the line can also be installed or removed without impacting network operations. If a DNO used dynamic line ratings on a number of lines, it might be appropriate to hold spare units, in which case replacement on failure of the 37 From the USi, the manufacturers of the Power Donut 38 A video demonstrating the fairly simple installation procedure is available from the manufacturer s website. 35

42 measuring device should take no more than an hour plus travel time. Otherwise, these are off the shelf items and hence readily available. The Power Donut is powered from the electromagnetic field of line current, however that current must be greater than 50 A (it should be noted that this is a limitation on the use of this device although with typical conductor ratings measured in hundreds of amperes this should not be a problem). If a line is out of service for more than 12 hours, then this device will require a minimum 120 A before charging commences. Therefore, should the normal operating current range be between 50 A and 120 A, it might be necessary to manually charge the unit following an extended outage. Otherwise, maintenance would appear to be minimal. Maintenance of a weather station would depend on the particular system chosen. Solar radiation sensors might require cleaning, and any dirt or other material in anemometer bearings might affect wind speed measurement. Overall, the weather station is likely to require approximately annual maintenance and calibration. Some form of power supply will be required for the weather station, preferably solar. Operations staff are likely to require some training on the first dynamic line rating system to understand changing power flows on the network and what impact they might have on alarm and control setpoints. However the principles involved are intuitive and directly repeated for each installation. Designing failsafe mechanisms to curtail DG should the dynamic rating system be compromised in anyway should ensure there is no negative effect on CML, CI etc. Customers on the same line as DG that is allowed to connect because thermal ratings are increased should see no impact (unless there other, voltage related issues). Rather, access to greater information about network parameters such as current and voltage might allow faster identification of problems Planning The interaction between dynamically increasing the capacity of a line and P2/6 security requirements will need to be considered on a case by case basis. In general the line capacity increase will be related to curtailable DG rather than load increases, and so it is unlikely to require other changes to the network to maintain P2/6compliance. Dynamically increasing the capacity of a line might however provide a significant increase in transfer capability, thus allowing the line to assist in maintaining P2/6 compliance for other parts of the network. The life expectancy of the Power Donut is greater than 20 years according to the manufacturer s information regarding the first units that were in service, although the latest units have considerably more features and capabilities, and so its life expectancy could not be judged. Other components of the dynamic line rating system, namely the controller and the communications to the DG likely to be standard components and so cost of end of life replacement will be spread over a broader range of technologies. The overall cost of dynamic line rating would appear to be low, particularly compared to the cost of increasing line capacity by new line reinforcements. The Power Donut package including software to communicate with the DNO control system has been quoted at approximately 8,000, and weather stations are similarly priced. The most complex part of the upfront engineering work to set up the scheme will be determining where to 36

43 measure the weather or line conditions to ensure that the true bottlenecks on the line are being captured. If the dynamic rating system has been triggered by a wind generation connection application, it might be possible to coordinate wind data collation (something in the best interest of the developer who would otherwise be likely to pay for the DNO costs). The communications to the DG should be able to be achieved cost effectively if integrated at the time the DG connects and using the capabilities of standard protection relays. Where the dynamic line rating system is being used in conjunction with wind generation, the cost of curtailment to the DG developer is likely to be minimal given the aforementioned correlation between conductor capacity and wind generation. This might not be the case for other types of generation, in which case load factors could be analysed against the expected capacity increases to run a last on, first off scheme similar to that used in the Orkney RPZ Other Once again, the use of dynamic ratings by one UK DNO, particularly in the context of an RPZ, might prohibit similar projects from qualifying from IFI or RPZ funding. However, incremental variations might include using dynamic rating on lower voltages, using it across a broader area and also using it in conjunction with DG other than wind generation. Dynamic rating based on different technologies or algorithms to that used by Central Networks should also qualify. 6.5 Summary of Results Each of the four technologies examined can now or will soon become part of the DNOs standard set of solutions to be considered when solving a network problem. None were found to be a perfect solution for every problem. This will represent a new challenge for DNOs who have traditionally been faced with a very limited set of options, such as upgrade transformers or a line, build a new substation or line, transfer load and so on. Of these, the use of FACTs devices is most likely to qualify for IFI or RPZ funding. The other three technologies could also qualify if it could be proven that they were being implemented in a novel fashion. 37

44 7 RECOMMENDATIONS 7.1 Introduction This report has found that each of the technologies examined might, in some circumstances, be an appropriate technology to employ now or within the next 5 years to solve particular problems. However a number of barriers were identified which might prevent or delay implementation. These are summarised with recommendations for overcoming them in this section. 7.2 Manufacturers General All of the technologies examined will, when implemented, affect several areas of a DNOs business, including planning, design, project delivery, operation and maintenance. It is therefore recommended that manufacturers of ANM products aimed at the distribution network market seek to better understand the DNO processes of investment planning and engage the DNO at all levels throughout this process. Particular attention needs to be paid to the planning department of a DNO business. For example, a dynamic rating system or a new controller might provide the most benefit in the area of operational flexibility and manufacturers might target operational staff for discussions about their products. However, without engaging planners during the process of making investment decisions, the planners will continue to design the network to be operated in the way it has always been operated. This will mean that potential benefits of reducing capital expenditure will be lost, reducing the value of the technology overall to the DNO. In addition, consideration needs to be given to how new technologies will integrate into existing network designs. For example, a modular, portable STATCOM might be theoretically a valuable tool for managing long term changes in the network, unless standard substation designs do not have the necessary space, spare circuit, protection etc to accommodate it. The electricity industry is naturally very conservative regarding new technologies that might not have the same level of reliability and safety as existing equipment. The relatively slow uptake of XLPE cables at extra high voltage is a good example of this. Although now it is common practice to use XLPE cables at voltages of 132 kv and above, acceptance of the technology required many years of evaluation and trials. DNOs must be comfortable that any technology that is new to them and that will form a critical element in the chain of supply of electricity, such as some of those examined in this report, has undergone a full trial process. Manufacturers must be prepared to fully demonstrate how their technologies will reliability and safety concerns Inline Voltage Regulators There are several manufacturers of IVRs worldwide, but only one appears to have had any involvement in the Great Britain market. This is possibly because manufacturers have viewed opportunities for IVR as limited, as Great Britain does not have the long radial lines with excessive voltage drop that has been the traditional problem resolved by an IVR. 38

45 However, with increasing levels of DG being installed around the world, opportunities for IVRs might increase. Therefore it is recommended that manufacturers pay more attention to the use of IVRs as means of potentially resolving voltage rise issues with DG and discuss this with DNOs (particularly those DNOs with rural sections of network) SVCs and STATCOMs SVCs and particularly STATCOMs can provide excellent power quality support to a network. However, there is a strong perception in the electrical industry that these are transmission devices only, are too expensive and do not have a long service history, despite their increasing use on windfarms seeking to comply with the grid code. To overcome these perceptions, manufacturers will have to ensure their devices gain a local service history at the distribution level. One way to do this would be to work with individual DNOs to identify ways to take advantage of the RPZ and IFI schemes. This is currently being done by manufacturers of, for example, certain energy storage and fault limiting devices. As the application of these devices will be new to almost all DNOs, manufacturers should also consider offering network models to DNOs that can be easily incorporated into existing planning tools. This will allow DNOs to readily assess the potential benefits of an SVC or STATCOM compared to other options for solving particular problems. Finally, cost is likely to continue to be a barrier as it has been on transmission networks. Manufacturers might have to consider means of reducing the total installed cost. Modular, mobile devices as proposed for the D-STATCOM should go some way towards achieving this, but more might be required Active Voltage Controllers The biggest concern expressed by DNOs 39 regarding active voltage controllers and similar control schemes is that of creating niche pockets of non-standard technology around the network and causing legacy problems. In part, these concerns related to the operational and long term maintenance issues associated with complex and non-standard logic sequences that might trigger regular reprogramming as the network changes or is reconfigured. It has been noted that off the shelf ANM systems are not currently available and that each system must be highly customised. Distributed micro-grid controllers will probably require maintenance and operations staff to gain new skills which might be difficult to maintain if the technology is only used in a few substations. In general, the trend is for networks to become as uniform and non-complex as possible due to the increasing importance of efficient use of human resources. The recent shift away from tapered networks to uniform 415 V cables is one example of this process. It has also been noted that despite the many smart protection relays now being installed in substations, very little of the available functionality is being used. This indicates a strong tendency away from non-standard equipment, settings or logic. These concerns highlight the need to find modular solutions that will allow staff to plan, design, maintain and operate ANM systems across the network in a standard manner, 39 For example, SP Systems, Network management systems for active distribution networks a feasibility study,

46 preferably not dissimilar to current methods. Systems requiring DNOs to acquire completely new skills or to radically change staff roles, culture or business structures seem unlikely to be seen as appropriate solutions for implementation within a short time frame. This is particularly true in the current economic climate with many organisations already finding it difficult to recruit people with sufficient knowledge and experience of designing and operating existing systems. However, it must be noted that DNOs are obliged under their licences to provide least cost solutions to connecting parties regardless of resource issues. To find acceptance for micro-grid controllers, manufacturers will have to address these concerns. Controllers must be as modular, or plug and play as possible, so that they can be rapidly deployed without requiring individual design from planners, protection engineers, communications engineers, substation designers and so on. In addition, concerns regarding changes to the network configuration must be met. If an active voltage controller needs to know that there is a new open point in a particular circuit then how will that information be captured? Will staff have to familiarise themselves with a unique system at each substation? Most DNOs will see this as unsustainable. Micro-grid controller functionality could be located in the central control room, which will always contain a variety of control, logic and communications equipment. Control skills will generally be concentrated in the personnel working in and around the control centre, and equipment located there is less likely to be overlooked in knowledge transfer. This would lose some of the advantages of distributed controllers, including savings on the need for reliable communications but might also reduce concerns about lost and forgotten customised systems. Regardless of the location of the micro-grid controller, reliability and cost of communications will be a concern. However there are an increasing number of communications options available today, including GPRS which is inherently replicated with multiple paths available between base stations. Therefore it is recommended that manufacturers pay particular attention to achieving low cost, reliable and standard communications that will increase confidence in the micro-grid controllers. The success of the main trial of the ENMAC DPA module to provide state estimation capability and increase visibility of a distribution network suggests that there is a market for these more sophisticated control systems at the distribution level. The micro-grid controllers considered here have similar state estimation capabilities. Manufacturers could therefore consider providing operators with a view of the estimated network parameters. Other than the benefit of greater real time network understanding provided by state estimation, manufacturers should consider how easy it would be to add further value to their products. Of particular interest to DNOs might be automation measures that will impact positively on measures such as CML. This added value might make propagation of the technology easier for the DNO to justify Dynamic Rating Systems Many of the concerns regarding bespoke, overly customised systems apply equally to control based on dynamic ratings, although the technologies discussed in this report are measuring devices and interpreting software rather than complete controllers. It is 40

47 recommended that manufacturers of devices designed for dynamic ratings assist DNOs by ensuring their products are easily integrated into existing SCADA and control systems. 7.3 DNOs Integration of New Technologies and Practices Where there are no significant technical barriers to an ANM technology, the main challenge to be met appears to be integrating the use of the technology into the DNO s business so that it becomes a well known solution to be used when applicable. The electricity distribution industry consists of large amounts of long life, capital intensive assets. There have historically been few drivers to embrace new technologies. There are two ways in which these ANM technologies could be integrated into the network. The first is to consider the standard end to end investment planning processes, especially where this relates to the processing of DG connection applications. It is recommended that DNOs consider the processes that they have in place for these tasks to determine what needs to change to be able to incorporate new ANM technologies. The best approach would appear to be for system planners and designers to ensure that they have each technology as one of a toolbox of technologies to call upon when appropriate. System planners and designers are frequently under significant time pressure and need to have sufficient technical and financial information available to be able to make fast decisions. Therefore, to add a new ANM technology such as those discussed in this report to an organisation s toolbox, consideration of the following is recommended. To ensure that the following steps are undertaken, management will need to put in place appropriate forms of organisational support. To ensure cost data is available for assessment of the cost of different options and for applications for funding, procurement personnel might need to arrange standard supply contracts with manufacturers for purchase pricing, support costs, parts etc. This will require a joint effort with designers, operators and maintainers to develop standard equipment specifications. To ensure that planners can cater for curtailment of generation, standard terms of connection offers should be developed by commercial and legal personnel to allow DG the possibility of reducing upfront capital expenditure in return for accepting risk of occasional curtailment. Methods of estimating the extent of that curtailment will need to be developed, as in the Orkney RPZ case, so that developers can make informed decisions. This process should be coordinated with current reviews of DG connection contracts by Ofgem. To ensure system studies can incorporate these new technologies, planners might have to develop standard modules and techniques for modelling the new technologies. Where this function is outsourced, consultants will need to be made aware of the need to model these new technologies. Where achieving the benefits of the new technology relies on some changes to operating practice as well as network design, operating personnel will need to be involved to ensure the design is optimised with operating equipment and methods. Planners should consider operating methods as a way of achieving desired network 41

48 outcomes in the same way that they must consider transfer capabilities between substations to meet the P2/6 security standard. Finally, investment application templates should be changed to incorporate triggers for those preparing the documents to state that they have considered ANM techniques as a potential solution to the problem identified in the application. In these ways, a new technology can be gradually introduced into the normal planning processes of the business. Following the initial decision to commence using a new technology, other business changes will be required such as: To ensure efficient project specification, designers might need to create or modify standard designs for inserting the new technologies into the network. This might include substation designers, civil, protection and communication specialists as well as others as appropriate. Management and finance personnel will need to be made aware that at times, they might be asked to approve a project with novel elements. Maintenance personnel might need to develop new maintenance and spares strategies, as well as safe working practices. Operating personnel might need to be trained in operation of the new equipment and understand how standard operating practices might need to change to ensure the full benefits of the new technology are captured Regular Network Reviews The second and complementary approach is for each DNO to actively search their network for areas that might benefit from the technologies discussed in this report now. Regular planned reviews of the current state of the network, including DG connection applications might be warranted, once the planners have the recommended new technologies in their planning toolbox. It would be preferable to maximise the benefits achieved from introducing a new technology Specific RPZ Opportunity In some situations, particularly on 11 kv networks with potential voltage rise problems, IVRs might allow more DG to connect. IVRs might be particularly appropriate on feeders that already have small, mature windfarms connected that will soon seek to repower. However, one of the main technical concerns with IVRs is that changes in the network, including the sort of network configuration changes that are relatively frequent on the 11 kv network, are very likely to require settings changes. This problem might be managed where the IVR is integrated into a micro-grid controlled by an active voltage controller, or even one of the less sophisticated voltage control devices available such as a TAPP relay. This would have the dual benefit of extending the control range of the controller, and would be likely to qualify for RPZ funding, at least for the first such project Asset Replacement One of the main potential benefits of using dynamic ratings is to increase capacity on an existing line and thus avoid having to build a new line with the attendant planning 42

49 permission costs and delays. This might be particularly attractive to a DG developer when offered as a connection solution. Where consideration of dynamic ratings is triggered by a wind generation connection application, it is recommended that the DNO consider negotiating with the developer to make common use wind monitoring equipment and contracts. This should both decrease the costs and delays to both parties (particularly to the DNO, for whom wind measurement is not likely to be an embedded skill) and also help foster an ongoing collaborative relationship. Dynamic ratings could also be used as a diagnostic tool to provide greater accuracy when assessing when particular pieces of equipment require upgrading. Often lines are upgraded when planners suspect that an overhead line is nearing capacity due to a combination of measured demand at the substation, assumed load and diversity factors, assumed load growth, standard conservative seasonal line ratings and other assumptions. In this case, even without connected DG or demand side participation to control, using dynamic line rating equipment and techniques could allow investment to be deferred until actually necessary. If the measurement equipment was easily relocatable, then after the expected load growth had been achieved the devices could be moved around the network to the next areas of concern. It is recommended the DNOs consider this possibility as an incremental step towards greater active network management. 7.4 DG Developers For many developers, getting a network connection can be a complex task. It is generally unlikely that most developers will have current knowledge of all of the regulations, incentives, latest technologies and so on that will or could apply to their connection. It is probably unreasonable to expect developers to understand or demand particular connection solutions. However, it is important that developers do question whether the connection offers they receive constitute the least cost solution incorporating current best practice, even if they are unaware of what this is. In addition, developers seeking lower upfront capital costs should seek to discuss with DNOs the possibility of exchanging capital intensive options for ones involving more risk of curtailment and other flexible operating measures. Even if the end result is that the DG developer decides not to take on curtailment risks in some cases, forcing the DNOs to go through the process of considering new technologies will help embed the new technologies into the connection design process. Increased demand for more flexible connections will create more drivers for ANM technologies. 7.5 IFI/RPZ Schemes The IFI and RPZ mechanisms have been effective in bringing a number of technologies to full development stage and currently, various technologies are being trialled under these mechanisms. However, the next step is to determine how these trials can be transformed into widespread adoption. It is possible, although far from certain, that these mechanisms might be enough to ensure that this happens within the DNO company that has undergone the initial trial. However, the incentives are limited to the first time use of a technology by any DNO in the UK and therefore will not be able to drive the propagation of new technologies across the industry. 43

50 A revised version of the RPZ and IFI incentive schemes might modify the criteria regarding innovation to mean innovation that has not been used by that company before. This would provide appropriate recognition to the fact that many of the development costs associated with introducing a new technology are repeated within each new organisation. Different levels of incentive could be introduced that are set at levels to provide sufficient drivers to DNOs to adopt technologies that have been proven successful in other organisations. In doing this, it will be important not to discourage DNOs from being the first DNO to trial a technology. 7.6 Technical Standards for Voltage Design standards for the GB distribution networks contain a mix of probabilistic and deterministic technical requirements. Planners are required to plan the network to meet the P2/6 security standard, which has recently been modified to include recommendations on how to allow for the contribution of DG to system security. However, there are no equivalent clear recommendations regarding how to assess the potential positive or negative impacts of DG on meeting voltage limits. In addition, there are no guidelines regarding how to make allowance for the impact of the sorts of technologies discussed in the report. It was found that when using an IVR to increase allowable DG onto a feeder, in some circumstances an outage of the DG might result in system voltages reducing below accepted limits. Failure of each of the voltage controlling technologies examined (FACTS devices, IVRs and voltage controllers) must normally result in some action to prevent excessive voltage changes. However, these events are not in effect different to, for example, an outage on a loaded feeder. DNOs currently consider these situations when planning a network and generally aim to maintain the criteria set forth in standards such as Engineering Recommendation P28, written in The recommendations in this standard are primarily based on customer acceptance of the flicker effect in tungsten filament lamps. It is possible that a review of P28 and related standards could result in a more probabilistic approach taking into account the potential impact of active networks, including increasing levels of DG. 7.7 ENA Guidelines In general it was found that the two Engineering Technical Recommendations (ETRs) related to managing power and voltage issues with DG 40 provided a useful overview of potential ANM techniques and technologies. However, the detail provided was generally insufficient to be of use to a DNO seeking to actually implement these technologies. It is therefore recommended that these ETRs be updated following each successful implementation of a relevant RPZ or IFI project with information gathered from the DNOs regarding their actual experiences. 40 ETR 124 Guidelines for Actively Managing Power Flows Associated with the Connection of a Single Distributed Generation Plant and ETR 126 Guidelines for Actively Managing Voltage Levels Associated with the Connection of a Single Distributed Generation Plant 44

51 7.8 DWG It is recommended that future DWG projects continue to update the ANM register, which might otherwise rapidly become out of date. There are a significant number of ANM related projects occurring in the UK and around the world, and so the ANM Register should be a useful resource going forward. DWG Workstream 3 Project 1 delivered a definition of ANM, which is included here in Appendix A. However, a number of projects have been delivered since this time, and this definition could be updated. In particular, it is recommended that the definition clearly specify why ANM is being considered, and what benefits it is expected to deliver. Although widely supported in principle, one frequently mentioned problem with the RPZ scheme is that DNOs cannot act unilaterally 41,42. Developing an RPZ requires considerable and coordinated input from developers to assist the DNOs in locating suitable parts of the network. Such coordination amongst multiple parties is difficult to arrange. It is therefore recommended that the DWG consider using its membership base to distribute knowledge about the RPZ scheme to DG developers and assist with the required coordination, particularly where a DNO has identified suitable areas of network. 41 Letter from CE Electric UK to Ofgem re Innovation Funding, CE%20Electric%20Open%20Letter%20response.pdf 42 Ofgem workshop on IFI and RPZ funding initiatives, Minutes%20of%20IFI_RPZ%20Workshop%2021%20Nov.pdf 45

52 8 CONCLUSIONS Inline voltage regulators (IVRs), SVCs and STATCOMs, active voltage controllers and dynamic rating systems were assessed for their technical ability to be integrated into existing distribution networks. These were chosen as they are all currently or nearly commercially available. Each technology was found to be an appropriate solution to certain types of network problems, although not in every circumstance. IVRs can be a relatively inexpensive device to install on a feeder with DG connected to prevent excessive voltage rise and thus allow more DG to be connected. They consist of familiar and well proven components and should present few network integration issues. There are several suppliers, although not all have been marketing their products in the UK. Two technical concerns were found with use of the IVR in this fashion. It is likely that the settings and even the position of the IVR controller will be relatively sensitive to changes in network configuration. Using the IVR with some form of active voltage controller might assist with the former issue and system studies must determine how position sensitive the IVR will be. The other concern was that if the IVR was sitting on a low tap position and a large amount of DG on that feeder tripped, a voltage excursion might occur. Again, system studies would be required to determine how much of a problem this might be, considering the relatively fast tap changing speeds that are available. There are now several SVCs and STATCOMs available specifically for the distribution network and more are currently in development. They can significantly improve power quality on the network, however at a relatively high cost. At least one developer is developing a mobile, plug and play STATCOM which should help reduce costs and make a relatively attractive solution where traditional options are difficult to carry out. Several active voltage controllers are either available now or are in various stages of development. They can be either centralised or distributed controllers. Each method has various advantages and disadvantages, but both have few technical issues and should function as designed. The main concerns DNOs have with this type of technology is the risk of having non-standard, heavily customised devices scattered about the network causing difficulties for operators and maintainers. Various recommendations to overcome these concerns were given. In particular, manufacturers should seek to make their products as uniform and simple to install, operate and maintain as possible. A dynamic line rating system is currently being trialled by one DNO based on a combination of weather data and direct measurement of line parameters to allow increased DG connections without significant capital upgrades. In general, dynamic ratings are thought to have considerable benefits, particularly when combined with wind generation. In this case, higher generation will often be coincident with higher conductor ratings due to the cooling effect of the wind. However, there are several caveats to this general observation. The line capacity is quite dependant on the wind direction (which might be variable) as well as the wind speed, such that parallel wind will have less cooling effect than perpendicular wind. In addition, the overall capacity of the line will depend on the worst span, which might change from time to time with the local weather conditions. It is recommended that the DNO seeks to 46

53 collaborate with the wind generation developer to make use of the developer s wind analysis skills and equipment to ensure the best outcome. Other recommendations made in this report including reviewing the RPZ and IFI incentive schemes and also the technical standards for maintaining network voltage. The incentive schemes have been quite effective in bringing technologies to a trial stage on the network. However, there is no incentive for propagating successful technologies and best practices throughout the industry. Although the first DNO to trial a new technology might incur the bulk of the development costs, other DNOs seeking to adopt the technology will also incur considerable costs and this should be recognised. It is also recommended that the DWG consider taking on a coordinating role to help bring DG developers and DNOs together to discuss potential areas for RPZ funding. The existing voltage technical standards predate the current thinking regarding management of distribution networks with their increasing amount of DG. The security standard, P2/6 has recently been updated to factor in contributions to security from DG and the voltage standard P28 would benefit from a similar review. Similarly, it is recommended that the ENA standards relating to managing active power and voltage with DG connections be updated, particularly as more new technologies are trialled on the networks. Finally, it is recommended that the DWG ensure the ANM register is regularly updated, as this is a valuable source of information about ANM technologies. 47

54 Appendix A Project P01 Active Network Management Definitions Involved Parties Network operators network management, ancillary services, DSM. Generators energy trading, ancillary services. Energy suppliers energy trading. Customers DSM, QofS. Manufacturers suppliers of enabling technologies. BERR / Ofgem legislation, policy, security of supply. Research institutions research, development and demonstration. Consultants support of development and demonstration. Generators, suppliers or network operators (depending on ownership of the device) may undertake storage (of electrical energy). Scope & Scale As distribution networks develop to support increased levels of distributed generation it is likely that distribution networks will be managed actively only on the parts of the network where a need for intervention is identified. The rest of the distribution network will continue to operate in a passive mode with intervention only taking place for routine maintenance and fault management, as now until routine asset replacement provides increased facilities. As the architecture to enable active network management is developed it will drive changes to network design which will deliver increased functionality either based on specific need or as part of asset replacement. Generation may become less visible to transmission operators as it becomes embedded. Geographical areas that require active management may well change over time as generation and load changes or as network reinforcement is undertaken. As more distributed generation, DSM and storage is connected to the distribution network the extent and levels of such active management are likely to increase. This will lead to increased levels of data and information about the operation of the distribution network but increasing issues associated with management of data and configuration management. Functional Requirements of Active Management Active management in a distribution network may involve management of some of the following elements in real time, time of day, seasonal or contractual arrangements: Voltage control Appendix A 1

55 Powerflow real and / or reactive power (to constrain power flows within equipment ratings) Utilisation of equipment dynamic ratings (such as thermal intertia and seasonal ratings) Fault level management (still under debate due to H&S issues) Loss minimisation (particularly in relation to circulating current issues) Network stability Frequency control (to support NGT s requirements under the Gcode / Dcode or as part of management of an islanded network) Auto-change-over schemes Synchronisation (following islanding) Island operation (due to problems on higher voltage or source networks) Generator ramp rates DSM of customer load Provision of ancillary services Partial supply restoration following network faults Support of network maintenance Management of the network Considerations when implementing Active Management When implementing active management the following areas need to be considered: Safety (of staff and public) Legislation (Primary and secondary) Internal company policies and culture (DNOs, Generators) Economics / cost implications Security (cyber and physical) Data interface (protection, control, trading) Design, installation, operation and maintenance of equipment (including training) Operator interface Response time - real time (high speed protection, short time automation), human intervention response, message, contract period Generation / storage / load balance Appendix A 2

56 Equipment ratings and capability (existing, new and dynamic) Reliability & availability & quality of supply (CI, CML, P.28 issues) Scalability & adaptability (modular?) Data management Software and firmware management Interface with existing primary equipment Interface with existing secondary equipment Fall-back arrangements to fail safe situation (with communications or equipment failure) Reliability of secondary systems (including communication links) Equipment monitoring Generator education & training Customer education & training Appendix A 3

57 Appendix B Glossary ANM AVC CE Electric UK CI CML DNO DWG EDF ENA ENSG E.ON ETR FACTs GPRS IFI IGBT IVR Ofgem OLTC OPGN Active Network Management Automatic Voltage Control relay which takes a voltage setpoint to control an OLTC UK DNO Customer Interruptions Customer Minutes Lost Distribution Network Operator Distribution Working Group Electricité de France, UK DNO Electricity Networks Association, UK industry group Electricity Networks Strategy Group UK DNO Engineering Technical Recommendation series of documents released by the ENA to assist with network planning and design. Flexible AC Transmission devices shunt and series connected power electronics devices General Packet Radio Service common mobile technology used on GSM networks Innovation Funding Initiative Insulated Gate Bipolar Transistors Inline Voltage Regulator Office of Gas and Electricity Markets On Load Tap Changer Optical Power Ground Wire, system of incorporating a data cable in with the earth cable on overhead lines P2/6 Security standard mandated by DNO licences RPZ RTU SCADA Scottish Power Scottish Hydro STATCOM SVC TAPP United Utilities Registered Power Zone Remote Terminal Unit, field controller for the SCADA system Supervisory Control And Data Acquisition, central control scheme used by DNOs to view and control the network UK DNO UK DNO SVC which operates independently of system voltage. Static VAR Compensator, device for providing fast acting reactive power compensation typically using switched capacitors and thyristor controlled reactors. Transformer Automatic Paralleling Package UK DNO Appendix B 1

58 Appendix C Sample Questionnaire Benefits 1. Describe the product 2. What is the primary purpose/main market for this product, including voltage levels? 3. Does this product help a DNO trying to optimise the amount of DG on a section of network? If so, how? 4. Has the company done studies to quantify the benefit? 5. What other benefits can a DNO receive from using this product? 6. Do you consider that this product replaces a traditional solution? If so, what? Track Record 7. Describe the level of testing in the field that this product has undergone specifically on distribution networks with some DG. 8. How long has this product been on the market? 9. How many of these products are currently in use? Installation Impact 10. What does this product cost? Describe in general terms if necessary. 11. Describe your expectations regarding the involvement of different levels of DNO personnel with this product (eg engineers, technicians, operators, specialist consultants). Appendix B 2

59 12. What training is required? Who provides this training and where? How much will it cost the customer? 13. Does the product comply with relevant British Standards? Application Engineering 14. Describe what application engineering or system studies the DNO must undertake to gain these benefits: a) Initially b) Following changes to the physical network configuration 15. What data inputs are required? 16. What speed and reliability is required for those data inputs? 17. What are the communication requirements? 18. Can the communication and data requirements achieved be achieved using most DNOs existing equipment? Operational Impact 19. What is the failure rate of this product? 20. What are the consequences of failure of this product: a) To operate as expected? b) To operate at all? 21. After failure, how long does this product take to repair/replace? Appendix B 3

60 22. DNOs have several key performance indicators, in particular Customer Minutes Lost (CML) and Customer Interruptions (CI). What, if any, negative or positive impact do you consider this module will have on these or other indicators? 23. How quickly does this product respond to significant changes to the network (eg a DG trip)? 24. What are the safety and environmental impacts of this product? 25. How adaptable is this product to meet changing network requirements, eg new DG? Maintenance Impact 26. What is the expected life of the product? 27. How often does this product need maintenance? 28. What costs will be incurred for upgrades, system maintenance, spares etc? Other Comments Appendix B 4