. (2010) 'Evaluating the bene ts of an electrical energy storage system in a future smart grid.', Energy policy., 38 (11). pp. 7180-7188. Further information on publisher's website:http://dx.doi.org/10.1016/j.enpol.2010.07.045Publisher's copyright statement: NOTICE: this is the author's version of a work that was accepted for publication in Energy policy. Additional information:Use policyThe full-text may be used and/or reproduced, and given to third parties in any format or medium, without prior permission or charge, for personal research or study, educational, or not-for-pro t purposes provided that:• a full bibliographic reference is made to the original source • a link is made to the metadata record in DRO • the full-text is not changed in any way The full-text must not be sold in any format or medium without the formal permission of the copyright holders.Please consult the full DRO policy for further details. AbstractInterest in electrical energy storage systems is increasing as the opportunities for their application become more compelling in an industry with a back-drop of ageing assets, increasing distributed generation and a desire to transform networks into Smart Grids. A field trial of an energy storage system designed and built by ABB is taking place on a section of 11kV distribution network operated by EDF Energy Networks in Great Britain. This paper reports on the findings from simulation software developed at Durham University that evaluates the benefits brought by operating an energy storage system in response to multiple events on multiple networks. The tool manages the allocation of a finite energy resource to achieve the most beneficial shared operation across two adjacent areas of distribution network. Simulations account for the key energy storage system parameters of capacity and power rating. Results for events requiring voltage control and power flow management show how the choice of operating strategy influences the benefits achieved. The wider implications of these results are discussed to provide an assessment of the role of electrical energy storage systems in future Smart Grids.

This paper presents how implementing the new concept of aggregating a portfolio of DER, requires DSO and TSO control tools to be adapted. DER aggregation requires the coordination of numerous small generation units, that are too small to individually bid on energy markets or provide ancillary services. DEFINITIONSA Virtual Power Plant, VPP, is a flexible representation of a portfolio of smaller generators and demands. It creates a single operation profile from a composite of parameters characterising each contributor to the portfolio. The VPP is characterised by a set of parameters usually associated with a traditional transmission connected generator, such as scheduled output, ramp rates, voltage regulation capability and reserves. Furthermore, as the VPP also incorporates controllable demands, parameters such as demand price elasticity and load recovery patterns are also used for characterisation of the VPP.This work was produced by the FENIX project. This project is a collaborative R&D project, partly funded by the European Commission within the 6 th Framework Program for Research, that aims at demonstrating the value and the feasibility of the concept of DER aggregation.

The use of energy storage on distribution networks continues to attract interest as a means to increase the penetration of distributed generation from renewable resources and provide wider network performance improvements. In mid 2009 a 600 kW, 200 kWh Lithium-Ion battery with a STATCOM power electronic interface will be field tested on an 11kV radial distribution network in the UK. Load flow modelling is being used to assess the operating procedures that should be trialled to achieve selected network performance improvements. At present two targets have been evaluated; reduce the steady-state voltage fluctuation at the point of common connection, and reduce the reverse power flow when distributed generation is exporting more power than the local demand. Several modes of operation have been used to achieve these goals, and their strengths and weaknesses have been evaluated.

Existing approaches to the design, control and operation of 11 kV distribution networks often restrict optimal utilization. When confronting the increasing demand and growing amount of distributed generation being connected to the networks, it is essential for distribution system operators to employ new and more active network management practices. This paper presents and discusses a range of active voltage management schemes based on coordinated voltage control. These schemes can be used to improve the voltage profile in 11kV distribution networks and increase their ability to accommodate distributed generation. Technical limitations and commercial barriers are discussed. Two case studies based on EDF Energy distribution systems are presented. Both systems experienced voltage issues associated with the presence of distributed generation and innovative active control scheme trials have been installed. The functionality of each scheme is assessed based on a number of factors such as: ability of the scheme to increase network capacity, reliability and accuracy.

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