This paper presents an investigation of the potential for coordinated charging of electric vehicles to i) reduce the CO 2 emissions associated with their charging by selectively charging when grid carbon intensity (gCO 2 /kWh) is low and ii) absorb excess wind generation in times when it would otherwise be curtailed. A method of scheduling charge events that seeks the minimum carbon intensity of charging while respecting EV and network constraints is presented via a time-coupled linearised optimal power flow formulation, based on plugging-in periods derived from a large travel dataset. Schedules are derived using real half-hourly grid intensity data; if charging in a particular event can be done entirely through use of renewable energy that would otherwise have been curtailed, its carbon intensity is zero. It was found that if 'dumb' charged from the current UK mainland (GB) grid, average emissions related to electric vehicle (EV) charging are in the range 35-56 gCO 2 /km; this can be reduced to 28-40 gCO 2 /km by controlled charging -approximately 20-30% of the tailpipe emissions of an average new petrol or diesel car sold in Europe. There is potential for EVs to absorb excess wind generation; based on the modelled charging behaviour, 500,000 EVs (20% of Scotland's current car fleet) could absorb around three quarters of curtailment at Scotland's largest onshore wind farm.
Power systems require a wide range of ancillary services in order to function and renewables will be expected to provide such services in line with their increasing penetration. This paper focuses on the participation of wind energy in response and reserve markets. We compare the present situation in Great Britain (GB) and Spain, and make recommendations to support future development. Wind is already participating in a limited range of ancillary services in both countries: frequency response in GB and reserve services in Spain. We analyse the effects of market design, subsidy arrangements, and systemspecific needs on participation of wind in these markets, and then make policy recommendations designed to enable increased participation from wind. Our recommendations include the use of short-term markets to enable the use of accurate wind power forecasts, capacity-based subsidy schemes to avoid distorting ancillary service markets, and facilitating the participation of aggregated (single and mixed technology) resources. Country-specific recommendations include revising the current settlement process in GB to remove the incentive to overestimate short-term generation forecasts, and establishing a competitive frequency containment reserve market in Spain. These recommendations are supported by analysis of publicly available market data.
The proliferation of distributed generation and the electrification of heat and transport pose significant challenges to distribution system operators (DSOs), and transmission system operators (TSOs). These challenges include the choice between network upgrades or operating increasingly constrained networks, with a reliance on the flexibility of distributed energy resources (DERs). This paper presents a novel market based coordination scheme, which allows both the DSO and TSO to access DER flexibility, while respecting distribution system limits. The DSO's objective in this work is to minimise the cost incurred by DSO adjustments to DERs, required to ensure stable distribution network operation. The methodology presented has the advantages of being compatible with existing TSO balancing market operation, and scalable enough to include multiple DSO markets coordinating with the TSO. The approach is demonstrated on a section of GB distribution network, using high DER growth scenario data for the year 2030. The case studies demonstrate the proposed DSO market mechanism to maintain thermal and voltage limits during periods of peak demand and DER output. The DSO is given priority in using DERs to solve distribution network constraints, however, significant flexibility remains for the TSO even during periods of peak demand and maximum export.
Optimisation and Analysis Toolbox for power Systems analysis (OATS) is an open-source simulation tool for steady-state analyses of power systems problems distributed under the GNU General Public License (GPLv3). It contains implementations of classical steady-state problems, e.g. load flow, optimal power flow (OPF) and unit commitment, as well as enhancements to these classical models relative to the features available in widely used open-source tools. Enhancements implemented in the current release of OATS include: a model of voltage regulating on-load tap-changing transformers; load shedding in OPF; allowing a user to build a contingency list in the security constrained OPF analysis; implementation of a distributed slack bus; and the ability to model zonal transfer limits in unit commitment. The mathematical optimisation models are written in an open-source algebraic modelling language, which offers high-level symbolic syntax for describing optimisation problems. The flexibility offered by OATS makes it an ideal tool for teaching and academic research. This paper presents novel aspects of OATS and discusses, through demonstrative examples, how OATS can be extended to new problem classes in the area of steady-state power systems analysis.
As part of the transition from distribution network operator to distribution system operator (DSO), decentralised pricing of energy is an area that needs to be considered. This paper considers different roles for the DSO in facilitating distributed markets including the decentralised and centralised approaches. The latest work in distributed markets has been reviewed including two major pilot projects involving DSO type operation of distribution markets. The use of distribution locational marginal prices (DLMPs) in distributed markets has been studied as a promising means of directing investment and managing constraints in distribution systems. Some simple case studies involving DLMPs in an example distribution network were modelled using Matpower and it was seen that marginal prices could result in reduced losses and congestion if DLMPs are passed on to distributed energy resources. A case was considered of a bus with losses resulting in DLMPs 6% above the grid import cost and it was seen if the DLMP market was used a generator installed at this bus could reduce the cost of losses by up to 14%.
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