Electricity North West Ltd

Warrington, United Kingdom

Electricity North West Ltd

Warrington, United Kingdom
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Blair S.M.,University of Strathclyde | Booth C.D.,University of Strathclyde | Williamson G.,Parsons Brinckerhoff | Poralis A.,Parsons Brinckerhoff | Turnham V.,Electricity North West Ltd.
IEEE Transactions on Power Delivery | Year: 2017

Dependable power quality (PQ) monitoring is crucial for evaluating the impact of smart grid developments. Monitoring schemes may need to cover a relatively large network area, yet must be conducted in a cost-effective manner. Real-time communications may not be available to observe the status of a monitoring scheme or to provide time synchronization and, therefore, undetected errors may be present in the data collected. This paper describes a process for automatically detecting and correcting errors in PQ monitoring data, which has been applied in an actual smart grid project. It is demonstrated how to: Unambiguously recover from various device installation errors; enforce time synchronization between multiple monitoring devices and other events by correlation of measured frequency trends; and efficiently visualize PQ data without causing visual distortion, even when some data values are missing. This process is designed to be applied retrospectively to maximize the useful data obtained from a network PQ monitoring scheme, before quantitative analysis is performed. This work therefore ensures that insights gained from the analysis of the data-A nd subsequent network operation or planning decisions-A re also valid. A case study of a U.K. smart grid project, involving wide-scale distribution system PQ monitoring, demonstrates the effectiveness of these contributions. All source code used for this paper is available for reuse. © 2016 IEEE.

Shaw R.,Electricity North West Ltd. | Shaw R.,University of Surrey | Attree M.,Electricity North West Ltd. | Jackson T.,University of Surrey
Energy Policy | Year: 2010

A more sustainable energy system will alter the current patterns of electricity demand and generation. This means technical, commercial and regulatory change for electricity network systems such as distribution networks. This paper traces the links in Great Britain between changes in energy policy since privatisation, changes in the objectives of the electricity regulator and changes in the objectives of the distribution networks and their owners, the distribution network operators (DNOs). The paper identifies tensions in regulatory policy and suggests reforms to the regulatory framework to support a lower-carbon future. DNOs are licensed regional infrastructure providers. In addition to their network services, the network companies can potentially deliver public policy objectives to facilitate heat infrastructure, energy-efficiency and distributed renewables. The paper identifies the potential benefits of a novel approach to facilitating renewable energy feed-in tariffs for electricity and heat, using DNOs. © 2010 Elsevier Ltd. All rights reserved.

Wang L.,Northumbria University | Liang D.H.,DNV GL | Crossland A.F.,Durham University | Taylor P.C.,Northumbria University | And 2 more authors.
IEEE Transactions on Smart Grid | Year: 2015

A method for the coordination of multiple battery energy storage systems (BESSs) is proposed for voltage control in low-voltage distribution networks (LVDNs). The main objective of this method is to solve over-voltage problems with multiple suitably sized energy storage systems. The performance of coordinated control is compared with noncoordinated control using both a real-time digital simulator and a MATLAB model of a real U.K. LVDN with a high installed capacity of solar photovoltaics. This is used to show that coordinated control is robust and effective at preventing voltage rise problems in LVDNs. The proposed coordinated control scheme is able to use the BESSs more evenly, and therefore reduces the costs of battery replacement to the storage operator in terms of both number of batteries and maintenance visits. © 2015 IEEE.

Crossland A.F.,Durham University | Jones D.,Electricity North West Ltd | Wade N.S.,Newcastle University
International Journal of Electrical Power and Energy Systems | Year: 2014

In light of the expansion of domestic photovoltaic (PV) systems in the UK, there are concerns of voltage rise within LV networks. Consequently, network operators are interested in the costs and benefits of different technologies to manage their assets. This paper examines the particular case for distributed energy storage. A heuristic planning tool is developed using a genetic algorithm with simulated annealing to investigate the problem of locating and sizing energy storage within LV networks. This is applied to investigate the configuration and topologies of storage to solve voltage rise problems as a result of increased penetration of PV. Under a threshold PV penetration, it is shown that distributed storage offers a financially viable alternative to reconductoring the LV network. Further, it is shown that a configuration of single phase storage located within the customer home can solve the voltage problem using less energy than a three phase system located on the street. © 2014 Elsevier Ltd. All rights reserved.

Crossland A.,Durham University | Jones D.,Electricity North West Ltd | Wade N.,Durham University
IET Conference Publications | Year: 2013

With the high growth in distributed generation in the UK and resulting challenges in distribution, there is a need for network operators to develop cost based tools to plan for and control technologies such as energy storage. This paper presents three methods for locating storage in LV networks to solve voltage rise problems. The methods are compared and evaluated and it is shown that careful heuristic selection and storage located in homes can provide significant savings for network operators.

Anuta O.H.,Newcastle University | Taylor P.,Newcastle University | Jones D.,Electricity North West Ltd | McEntee T.,Electricity North West Ltd | Wade N.,Newcastle University
Renewable and Sustainable Energy Reviews | Year: 2014

Energy storage systems (ESS) have the potential to make a significant contribution to planning and operation practises in power systems. While ESS can be used to provide multiple benefits in the power sector, widespread use has been restricted by high technology costs, lack of deployment experience, and the barriers and uncertainties caused by the present electricity market and regulatory structures that were designed for conventional electricity systems. This paper reviews countries with high renewable targets and with significant current or planned ESS deployments to ascertain the common problems affecting the use of ESS on the grid, and to establish where changes have been made or proposed to the electricity market and regulatory frameworks. Three major problems were identified as the undetermined asset class for ESS and unbundled electricity system limiting stakeholders from determining and realising multiple ESS benefits; low electricity market liquidity and changing market conditions; and a lack of common standards and procedures for evaluating, connecting, operating and maintaining ESS. Based on the established barriers, recommendations to update or create policies, regulation and market arrangements to increase the viability and wider use of grid level ESS are discussed. The three key regulatory and policy recommendations were identified as an alignment of renewable policies to that of ESS; creating a separate asset class for ESS and associated rules for regulated and competitive operations; and standardising assessment frameworks, connection and operational procedures for the use of ESS. Finally, three main electricity market recommendations include updating rules to support simultaneous ESS operation across wholesale, ancillary services and capacity markets; updating market rules to allow compensation for flexible and highly accurate responsive demand and generation technologies, such as ESS; and updating market ancillary services energy requirements. © 2014 Elsevier Ltd.

Schachter J.A.,University of Manchester | Mancarella P.,University of Manchester | Moriarty J.,Queen Mary, University of London | Shaw R.,Electricity North West Ltd
Energy Policy | Year: 2016

Classical deterministic models applied to investment valuation in distribution networks may not be adequate for a range of real-world decision-making scenarios as they effectively ignore the uncertainty found in the most important variables driving network planning (e.g., load growth). As greater uncertainty is expected from growing distributed energy resources in distribution networks, there is an increasing risk of investing in too much or too little network capacity and hence causing the stranding and inefficient use of network assets; these costs are then passed on to the end-user. An alternative emerging solution in the context of smart grid development is to release untapped network capacity through Demand-Side Response (DSR). However, to date there is no approach able to quantify the value of ‘smart’ DSR solutions against ‘conventional’ asset-heavy investments. On these premises, this paper presents a general real options framework and a novel probabilistic tool for the economic assessment of DSR for smart distribution network planning under uncertainty, which allows the modeling and comparison of multiple investment strategies, including DSR and capacity reinforcements, based on different cost and risk metrics. In particular the model provides an explicit quantification of the economic value of DSR against alternative investment strategies. Through sensitivity analysis it is able to indicate the maximum price payable for DSR service such that DSR remains economically optimal against these alternatives. The proposed model thus provides Regulators with clear insights for overseeing DSR contractual arrangements. Further it highlights that differences exist in the economic perspective of the regulated DNO business and of customers. Our proposed model is therefore capable of highlighting instances where a particular investment strategy is favorable to the DNO but not to its customers, or vice-versa, and thus aspects of the regulatory framework which may need altering. The case study results indicate that DSR can be an economical option to delay or even avoid large irreversible capacity investments, thus reducing overall costs for networks and end customers. However, in order for the value and benefits of DSR to be acknowledged, a change in the regulatory framework (currently based on deterministic analysis) that takes explicit account of uncertainty in planning, as suggested by our work, is required. © 2016

Martinez Cesena E.A.,University of Manchester | Turnham V.,Electricity North West Ltd | Mancarella P.,University of Manchester
Electric Power Systems Research | Year: 2016

Under the current UK regulatory framework for electricity distribution networks, asset upgrades are planned with the objectives of minimising both capital costs (and thus customer fees) and social costs such as those associated with carbon emissions and customer interruptions. This approach naturally results in economic trade-offs as network solutions meant to reduce social costs typically increase (sometimes significantly) capital costs, and vice versa. This can become an issue in a smart grid context where new operational solutions such as Demand Response (DR) may emerge. More specifically, even though there is a general belief that smart solutions will only provide benefits due to their potential to displace investments in costly assets (e.g., lines and substations), they may also introduce trade-offs associated with increased operational expenditure, power losses and emissions compared with networks with upgraded assets. On the other hand, the flexibility inherent in smart solutions could be used to balance the different types of costs, leading to attractive cost trade-offs if properly modelled, quantified and regulated. However, given the fundamental “non-asset” nature of DR, properly quantifying the resulting trade-offs so as to perform a like-for-like comparison with traditional planning strategies is a grand challenge. In this light, this article proposes a methodology to explicitly model and quantify capital and social cost trade-offs in distribution network planning, which can be incorporated into the existing regulatory framework. The results, based on real UK distribution networks, show that our proposed methodology can be used to explicitly model and regulate cost trade-offs. By doing so, it is possible to encourage more efficient levels of capital expenditure and social benefits by deploying the right mix of traditional asset-based and smart DR-based solutions. © 2016 Elsevier B.V.

Navarro-Espinosa A.,University of Manchester | Ochoa L.F.,University of Manchester | Randles D.,Electricity North West Ltd
2014 IEEE PES Innovative Smart Grid Technologies Conference, ISGT 2014 | Year: 2014

Significant penetrations of low carbon technologies in low voltage (LV) networks could result in voltage issues, thermal overloads of the lines, higher energy losses, etc. In this work, the meshed connection of LV feeders is investigated as one of the possible alternatives to minimise these impacts and, consequently, increase the corresponding hosting capacity. Two different technologies, photovoltaic panels (PV) and electric heat pumps (EHP) are studied for different penetration levels by using a real three-phase four-wire LV network in the North West of England. Profiles of loads, PV and EHP have a granularity of 30 minutes. Energy losses, voltage problems and thermal loading are studied. A Monte Carlo approach is considered in order to cater for the random nature of some parameters such as the location and size of low carbon technologies. Results for the studied LV network clearly indicate that meshed operation can indeed increase its ability to host higher penetrations of PV and EHP. © 2014 IEEE.

Navarro A.,University of Manchester | Ochoa L.F.,University of Manchester | Randles D.,Electricity North West Ltd
IEEE Power and Energy Society General Meeting | Year: 2013

The penetration of residential photovoltaic (PV) panels is increasing particularly in those countries with special incentives. The total PV installed capacity in the UK has increased from negligible to 1.2 GW since the Feed-In Tariff scheme was created in 2010. As a result, Distribution Network Operators (DNOs) are already experiencing voltage issues in low voltage (LV) feeders were clusters have appeared. This work proposes a Monte Carlo-based technique to assess the impacts of different PV penetrations on LV networks in order to estimate their corresponding hosting capabilities. Three-phase models of two real LV networks in the North West of England are studied considering 5-min resolution synthetic data for domestic load and PV generation. Voltage-related impacts are measured using the European Standard EN50160. Additionally, the importance of data granularity on the impact assessment is analyzed. Results for the studied LV networks indicate that feeders with greater lengths and larger number of customers tend to experience voltage issues with lower PV penetration levels. In terms of the granularity, it was found that hourly resolution analyses underestimate the voltage impacts of residential PV. © 2013 IEEE.

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