89 results found
Keppo I, Mazza A, Natalini D, et al., 2022, Introduction to EMP-E 2019 special issue “Modelling the implementation of ‘A Clean Planet for All’ strategy”, Energy Strategy Reviews, ISSN: 2211-467X
Fu P, Pudjianto D, Strbac G, 2020, Integration of power-to-gas and low-carbon road transport in Great Britain's future energy system, IET RENEWABLE POWER GENERATION, Vol: 14, Pages: 3393-3400, ISSN: 1752-1416
Strbac G, Pudjianto D, Aunedi M, et al., 2020, Role and value of flexibility in facilitating cost-effective energy system decarbonisation, Progress in Energy, Vol: 2, Pages: 042001-042001
<jats:title>Abstract</jats:title> <jats:p>Decarbonisation of the electricity system requires significant and continued investment in low-carbon energy sources and electrification of the heat and transport sectors. With diminishing output and shorter operating hours of conventional large-scale fossil fuel generators, there is a growing need and opportunity for other emerging technologies to provide flexibility in the context of grid support, balancing, security services, and investment options to support a cost-effective transition to a lower-carbon energy system. This article summarises the key findings from a range of studies investigating the potential benefits and challenges associated with the future low-carbon energy system. The key challenges associated with balancing local, national and regional objectives to minimise the overall cost of decarbonising the future energy system are also discussed. Furthermore, the paper highlights the importance of cross-energy vector flexibility, and coordination across electricity, heat, and gas systems which is critical for shaping the future low-carbon energy systems. Although most of the case studies presented in this article are based on the UK, and to some extent the EU decarbonisation pathways, the overall conclusions regarding the value of flexibility are relevant for the global energy transition.</jats:p>
Fu P, Pudjianto D, Zhang X, et al., 2020, Integration of hydrogen into multi-energy systems optimisation, Energies, Vol: 13, Pages: 1606-1606, ISSN: 1996-1073
Hydrogen presents an attractive option to decarbonise the present energy system. Hydrogen can extend the usage of the existing gas infrastructure with low-cost energy storability and flexibility. Excess electricity generated by renewables can be converted into hydrogen. In this paper, a novel multi-energy systems optimisation model was proposed to maximise investment and operating synergy in the electricity, heating, and transport sectors, considering the integration of a hydrogen system to minimise the overall costs. The model considers two hydrogen production processes: (i) gas-to-gas (G2G) with carbon capture and storage (CCS), and (ii) power-to-gas (P2G). The proposed model was applied in a future Great Britain (GB) system. Through a comparison with the system without hydrogen, the results showed that the G2G process could reduce £3.9 bn/year, and that the P2G process could bring £2.1 bn/year in cost-savings under a 30 Mt carbon target. The results also demonstrate the system implications of the two hydrogen production processes on the investment and operation of other energy sectors. The G2G process can reduce the total power generation capacity from 71 GW to 53 GW, and the P2G process can promote the integration of wind power from 83 GW to 130 GW under a 30 Mt carbon target. The results also demonstrate the changes in the heating strategies driven by the different hydrogen production processes.
Soder L, Tomasson E, Estanqueiro A, et al., 2020, Review of wind generation within adequacy calculations and capacity markets for different power systems, RENEWABLE & SUSTAINABLE ENERGY REVIEWS, Vol: 119, ISSN: 1364-0321
Giannelos S, Djapic P, Pudjianto D, et al., 2020, Quantification of the energy storage contribution to security of supply through the F-factor methodology, Energies, Vol: 13, Pages: 826-826, ISSN: 1996-1073
The ongoing electrification of the heat and transport sectors is expected to lead to a substantial increase in peak electricity demand over the coming decades, which may drive significant investment in network reinforcement in order to maintain a secure supply of electricity to consumers. The traditional way of security provision has been based on conventional investments such as the upgrade of the capacity of electricity transmission or distribution lines. However, energy storage can also provide security of supply. In this context, the current paper presents a methodology for the quantification of the security contribution of energy storage, based on the use of mathematical optimization for the calculation of the F-factor metric, which reflects the optimal amount of peak demand reduction that can be achieved as compared to the power capability of the corresponding energy storage asset. In this context, case studies underline that the F-factors decrease with greater storage power capability and increase with greater storage efficiency and energy capacity as well as peakiness of the load profile. Furthermore, it is shown that increased investment in energy storage per system bus does not increase the overall contribution to security of supply.
Pudjianto D, Djapic P, Strbac G, et al., 2020, DER reactive services and distribution network losses, Pages: 541-544
Managing synergies and conflicts between voltage support services and network losses is essential for the cost-effective integration of distributed energy resources (DERs). This study presents the results of studies investigating the impact of using DER reactive power services on distribution network losses. By using year-round optimal power flow analysis, a spectrum of studies on a number of distribution network areas in the southeast of Great Britain was performed to calculate distribution losses under different control scenarios. The studies demonstrate that the use of DERs to provide reactive services to the transmission system may increase distribution network losses. On the other hand, DER reactive services can also be optimised to minimise distribution losses. The studies also analysed the impact of optimising tap changing transformer settings on the distribution network losses reduction.
Orths A, Anderson CL, Brown T, et al., 2019, Flexibility from energy systems integration: supporting synergies mmong sectors, IEEE Power and Energy Magazine, Vol: 17, Pages: 67-78, ISSN: 1540-7977
Energy systems integration, or sector coupling, has several drivers that span climate impact mitigation and economics to social and regulatory considerations. A key question is what is sector coupling, and how does it impact the flexibility of the energy system? Here, the energy system includes several sectors - electricity, gas, heat, and transportation - that have been independent for decades in most countries except for their coupling via combined heat and power (CHP) units. In energy systems integration, some sectors may provide flexibility to other sectors, while other sectors will require flexibility when interlinking. To support these synergies among sectors, it is important to explore and quantify mutual interactions as well as seek examples of how these integrations can provide flexibility and other benefits. From the perspective of the electricity sector, it is important to ensure that there is enough flexibility in the interconnected systems to support decarbonization goals, such as those set in the Paris Agreement, while ensuring operational reliability.
Sun M, Djapic P, Aunedi M, et al., 2019, Benefits of smart control of hybrid heat pumps: an analysis of field trial data, Applied Energy, Vol: 247, Pages: 525-536, ISSN: 0306-2619
Smart hybrid heat pumps have the capability to perform smart switching between electricity and gas by employing a fully-optimized control technology with predictive demand-side management to automatically use the most cost-effective heating mode across time. This enables a mechanism for delivering flexible demand-side response in a domestic setting. This paper conducts a comprehensive analysis of the fine-grained data collected during the world’s first sizable field trial of smart hybrid heat pumps to present the benefits of the smart control technology. More specifically, a novel flexibility quantification framework is proposed to estimate the capability of heat pump demand shifting based on preheating. Within the proposed framework, accurate estimation of baseline heat demand during the days with interventions is fundamentally critical for understanding the effectiveness of smart control. Furthermore, diversity of heat pump demand is quantified across different numbers of households as an important input into electricity distribution network planning. Finally, the observed values of the Coefficient of Performance (COP) have been analyzed to demonstrate that the smart control can optimize the heat pump operation while taking into account a variety of parameters including the heat pump output water temperature, therefore delivering higher average COP values by maximizing the operating efficiency of the heat pump. Finally, the results of the whole-system assessment of smart hybrid heat pumps demonstrate that the system value of smart control is between 2.1 and 5.3 £ bn/year.
Sun M, Strbac G, Djapic P, et al., 2019, Preheating quantification for smart hybrid heat pumps considering uncertainty, IEEE Transactions on Industrial Informatics, Vol: 15, Pages: 4753-4763, ISSN: 1551-3203
The deployment of smart hybrid heat pumps can introduce considerable benefits to electricity systems via smart switching between electricity and gas while minimizing the total heating cost for each individual customer. In particular, the fully-optimized control technology can provide flexible heat that redistributes the heat demand across time for improving the utilization of low-carbon generation and enhancing the overall energy efficiency of the heating system. To this end, accurate quantification of preheating is of great importance to characterize the flexible heat. This paper proposes a novel data-driven preheating quantification method to estimate the capability of heat pump demand shifting and isolate the effect of interventions. Varieties of fine-grained data from a real-world trial are exploited to estimate the baseline heat demand using Bayesian deep learning while jointly considering epistemic and aleatoric uncertainties. A comprehensive range of case studies are carried out to demonstrate the superior performance of the proposed quantification method and then, the estimated demand shift is used as an input into the whole-system model to investigate the system implications and quantify the range of benefits of rolling-out the smart hybrid heat pumps developed by PassivSystems to the future GB electricity systems.
Strbac G, Pudjianto D, Aunedi M, et al., 2019, Cost-effective decarbonization in a decentralized market the benefits of using flexible technologies and resources, IEEE Power and Energy Magazine, Vol: 17, Pages: 25-36, ISSN: 1540-7977
Sun M, Teng F, Zhang X, et al., 2019, Data-driven representative day selection for investment decisions: a cost-oriented approach, IEEE Transactions on Power Systems, Vol: 34, Pages: 2925-2936, ISSN: 0885-8950
Power system investment planning problems become intractable due to the vast variability that characterizes system operation and the increasing complexity of the optimization model to capture the characteristics of renewable energy sources (RES). In this context, making optimal investment decisions by considering every operating period is unrealistic and inefficient. The conventional solution to address this computational issue is to select a limited number of representative operating periods by clustering the input demand-generation patterns while preserving the key statistical features of the original population. However, for an investment model that contains highly complex nonlinear relationship between input data and optimal investment decisions, selecting representative periods by relying on only input data becomes inefficient. This paper proposes a novel investment costoriented representative day selection framework for large scale multi-spacial investment problems, which performs clustering directly based on the investment decisions for each generation technology at each location associated with each individual day. Additionally, dimensionality reduction is performed to ensure that the proposed method is feasible for large-scale power systems and high-resolution input data. The superior performance of the proposed method is demonstrated through a series of case studies with different levels of modeling complexity.
Fu P, Pudjianto D, Zhang X, et al., 2019, Evaluating Strategies for Decarbonising the Transport Sector in Great Britain, IEEE Milan PowerTech Conference, Publisher: IEEE
Zhang X, Strbac G, Shah N, et al., 2019, Whole-system assessment of the benefits of integrated electricity and heat system, IEEE Transactions on Smart Grid, Vol: 10, Pages: 1132-1145, ISSN: 1949-3061
The interaction between electricity and heat systems will play an important role in facilitating the cost effective transition to a low carbon energy system with high penetration of renewable generation. This paper presents a novel integrated electricity and heat system model in which, for the first time, operation and investment timescales are considered while covering both the local district and national level infrastructures. This model is applied to optimize decarbonization strategies of the UK integrated electricity and heat system, while quantifying the benefits of the interactions across the whole multi-energy system, and revealing the trade-offs between portfolios of (a) low carbon generation technologies (renewable energy, nuclear, CCS) and (b) district heating systems based on heat networks (HN) and distributed heating based on end-use heating technologies. Overall, the proposed modeling demonstrates that the integration of the heat and electricity system (when compared with the decoupled approach) can bring significant benefits by increasing the investment in the heating infrastructure in order to enhance the system flexibility that in turn can deliver larger cost savings in the electricity system, thus meeting the carbon target at a lower whole-system cost.
Papadaskalopoulos D, Moreira R, Strbac G, et al., 2018, Quantifying the potential economic benefits of flexible industrial demand in the European power system, IEEE Transactions on Industrial Informatics, Vol: 14, Pages: 5123-5132, ISSN: 1551-3203
The envisaged decarbonization of the European power system introduces complex techno-economic challenges to its operation and development. Demand flexibility can significantly contribute in addressing these challenges and enable a cost-effective transition to the low-carbon future. Although extensive previous work has analyzed the impacts of residential and commercial demand flexibility, the respective potential of the industrial sector has not yet been thoroughly investigated despite its large size. This paper presents a novel, whole-system modeling framework to comprehensively quantify the potential economic benefits of flexible industrial demand (FID) for the European power system. This framework considers generation, transmission and distribution sectors of the system, and determines the least-cost long-term investment and short-term operation decisions. FID is represented through a generic, process-agnostic model, which however accounts for fixed energy requirements and load recovery effects associated with industrial processes. The numerical studies demonstrate multiple significant value streams of FID in Europe, including capital cost savings by avoiding investments in additional generation and transmission capacity and distribution reinforcements, as well as operating cost savings by enabling higher utilization of renewable generation sources and providing balancing services.
Pudjianto D, Papadaskalopoulos D, Moreira R, et al., 2018, Flexibility Potential of Industrial Electricity Demand: Insights from the H2020 IndustRE project, the 11th Mediterranean Conference on Power Generation, Transmission, Distribution and Energy Conversion
Pudjianto D, Papadaskalopoulos D, Moreira R, et al., 2018, Flexibility Potential of Industrial Electricity Demand: Insights from the H2020 IndustRE project, The 11th Mediterranean Conference on Power Generation, Transmission, Distribution and Energy Conversion
Teng F, Pudjianto D, Aunedi M, et al., 2018, Assessment of Future Whole-System Value of Large-Scale Pumped Storage Plants in Europe, Energies, Vol: 11, ISSN: 1996-1073
This paper analyses the impacts and benefits of the pumped storage plant (PSP) and its upgrade to variable speed on generation and transmission capacity requirements, capital costs, system operating costs and carbon emissions in the future European electricity system. The combination of a deterministic system planning tool, Whole-electricity System Investment Model (WeSIM), and a stochastic system operation optimisation tool, Advanced Stochastic Unit Commitment (ASUC), is used to analyse the whole-system value of PSP technology and to quantify the impact of European balancing market integration and other competing flexible technologies on the value of the PSP. Case studies on the Pan-European system demonstrate that PSPs can reduce the total system cost by up to €13 billion per annum by 2050 in a scenario with a high share of renewables. Upgrading the PSP to variable-speed drive enhances its long-term benefits by 10–20%. On the other hand, balancing market integration across Europe may potentially reduce the overall value of the variable-speed PSP, although the effect can vary across different European regions. The results also suggest that large-scale deployment of demand-side response (DSR) leads to a significant reduction in the value of PSPs, while the value of PSPs increases by circa 18% when the total European interconnection capacity is halved. The benefit of PSPs in reducing emissions is relatively negligible by 2030 but constitutes around 6–10% of total annual carbon emissions from the European power sector by 2050.
Pudjianto D, Strbac G, Boyer D, 2017, Virtual power plant: managing synergies and conflicts between transmission system operator and distribution system operator control objectives, CIRED 24th International Conference on Electricity Distribution, Publisher: IET, Pages: 2049-2052, ISSN: 2515-0855
In this study, the implementation of virtual power plant (VPP) as a means to coordinate the use of distributed resources for different control objectives by transmission system operator and distribution system operator is described. In order to illustrate the concept, a range of illustrative studies demonstrating the application of VPP concept on a real 11 kV system in Brixton will be presented, using data from the Low Carbon London project. The studies demonstrate the changes in the operating characteristics of the VPP area over a range of system operating conditions.
Strbac G, Aunedi M, Konstantelos I, et al., 2017, Opportunities for Energy Storage: Assessing Whole-System Economic Benefits of Energy Storage in Future Electricity Systems, IEEE Power and Energy Magazine, ISSN: 1540-7977
Pudjianto D, Gan CK, Cheiw YL, et al., 2017, Impact of the photovoltaic system variability on transformer tap changer operations in distribution networks, CIRED 2017, ISSN: 2515-0855
Pudjianto D, Strbac G, 2017, Assessing the value and impact of demand side response using whole-system approach, PROCEEDINGS OF THE INSTITUTION OF MECHANICAL ENGINEERS PART A-JOURNAL OF POWER AND ENERGY, Vol: 231, Pages: 498-507, ISSN: 0957-6509
This paper describes the whole-system based model called Whole-electricity System Investment Model to quantify the benefits of demand flexibility. Whole-electricity System Investment Model is a holistic and comprehensive electricity system analysis model, which simultaneously optimises the long-term investment decisions against real-time operation decisions taking into account the flexibility provided by demand. The optimisation considers the impact of demand side response across all power subsystems, i.e. generation, transmission and distribution systems, in a coordinated fashion. This allows the model to capture the potential conflicts and synergies between different applications of demand side response in supporting particularly intermittency management at the national level, improving capacity margin, and minimising the cost of electrification. The impact and value of demand side response driven by whole-system approach are compared against the impact and value of distribution system operator or transmission system operator centric (silo approaches) demand side response applications and the importance of control coordination between distribution system operator and transmission system operator for optimal demand side response is discussed and highlighted.
Aunedi M, Pudjianto D, Strbac G, 2017, Calculating system integration costs of low-carbon generation technologies in future GB electricity system, 5th IET International Conference on Renewable Power Generation (RPG) 2016, Publisher: Institution of Engineering and Technology
System integration costs (SIC) of generation technologies, also referred to as system externalities, include various categories of additional costs that are incurred in the system in addition to the cost of building and operating the generation capacity that is added to the system. SIC may include increased balancing cost, cost of additional backup capacity, cost of reinforcing network infrastructure and the cost of maintaining system carbon emissions. In this paper we present a whole-system approach to quantifying the SIC and explore different approaches to calculating the relative SIC of a generation technology when compared to another technology. The results show that the SIC of low-carbon generation technologies will significantly depend on the composition of the generation mix, with higher penetrations of variable renewables giving rise to a higher SIC. Also, SIC will significantly depend on the deployment level of flexible options such as more flexible generation technologies, energy storage, demand side response or interconnection. The additional system cost driven by low-carbon technologies can provide a very useful input to inform the energy policy and support the selection of the low-carbon portfolio with the lowest total system cost.
Green RJ, Pudjianto D, Staffell I, et al., 2016, Market Design for Long-Distance Trade in Renewable Electricity, Energy Journal, Vol: 37, Pages: 5-22, ISSN: 0195-6574
While the 2009 EU Renewables Directive allows countries to purchase some of their obligation fromanother member state, no country has yet done so, preferring to invest locally even where load factors arevery low. If countries specialised in renewables most suited to their own endowments and expandedinternational trade, we estimate that system costs in 2030 could be reduced by 5%, or €15 billion a year,after allowing for the costs of extra transmission capacity, peaking generation and balancing operationsneeded to maintain electrical feasibility.Significant barriers must be overcome to unlock these savings. Countries that produce more renewablepower should be compensated for the extra cost through tradable certificates, while those that buy fromabroad will want to know that the power can be imported when needed. Financial Transmission Rightscould offer companies investing abroad confidence that the power can be delivered to their consumers.They would hedge short-term fluctuations in prices and operate much more flexibly than the existingsystem of physical point-to-point rights on interconnectors. Using FTRs to generate revenue fortransmission expansion could produce perverse incentives to under-invest and raise their prices, sorevenues from FTRs should instead be offset against payments under the existing ENTSO-Ecompensation scheme for transit flows. FTRs could also facilitate cross-border participation in capacitymarkets, which are likely to be needed to reduce risks for the extra peaking plants required.
Konstantelos I, Pudjianto D, Strbac G, et al., 2016, Integrated North Sea grids: The costs, the benefits and their distribution between countries, Energy Policy, Vol: 101, Pages: 28-41, ISSN: 0301-4215
A large number of offshore wind farms and interconnectors are expected to be constructed in the North Searegion over the coming decades, creating substantial opportunities for the deployment of integrated networksolutions. Creating interconnected offshore grids that combine cross-border links and connections of offshoreplants to shore offers multiple economic and environmental advantages for Europe's energy system. However,despite evidence that integrated solutions can be more beneficial than traditional radial connection practices, nosuch projects have been deployed yet. In this paper we quantify costs and benefits of integrated projects andinvestigate to which extent the cost-benefit sharing mechanism between participating countries can impede orencourage the development of integrated projects. Three concrete interconnection case studies in the North Seaarea are analysed in detail using a national-level power system model. Model outputs are used to compute thenet benefit of all involved stakeholders under different allocation schemes. Given the asymmetric distribution ofcosts and benefits, we recommend to consistently apply the Positive Net Benefit Differential mechanism as astarting point for negotiations on the financial closure of investments in integrated offshore infrastructure.
Mohtashami S, Pudjianto D, Strbac G, 2016, Strategic distribution network planning with smart grid technologies, IEEE Transactions on Smart Grid, Vol: 8, Pages: 2656-2664, ISSN: 1949-3061
This paper presents a multiyear distribution network planning optimization model for managing the operation and capacity of distribution systems with significant penetration of distributed generation (DG). The model considers investment in both traditional network and smart grid technologies, including dynamic line rating, quadrature-booster, and active network management, while optimizing the settings of network control devices and, if necessary, the curtailment of DG output taking into account its network access arrangement (firm or non-firm). A set of studies on a 33 kV real distribution network in the U.K. has been carried out to test the model. The main objective of the studies is to evaluate and compare the performance of different investment approaches, i.e., incremental and strategic investment. The studies also demonstrate the ability of the model to determine the optimal DG connection points to reduce the overall system cost. The results of the studies are discussed in this paper.
Cooper SJG, Hammond GP, McManus MC, et al., 2016, Detailed simulation of electrical demands due to nationwide adoption of heat pumps, taking account of renewable generation and mitigation, IET Renewable Power Generation, Vol: 10, Pages: 380-387, ISSN: 1752-1416
This study quantifies the increase in the peak power demand, net of non-dispatchable generation, that may be required by widespread adoption of heat pumps. Electrification of heating could reduce emissions but also cause a challenging increase in peak power demand. This study expands on previous studies by quantifying the increase in greater detail; considering a wider range of scenarios, the characteristics of heat pumps and the interaction between wind generation and demand side management (DSM). A model was developed with dynamic simulations of individual heat pumps and dwellings. The increase in peak net-demand is highly sensitive to assumptions regarding the heat pumps, their installation, building fabric and the characteristics of the grid. If 80% of dwellings in the UK use heat pumps, peak net-demand could increase by around 100% (54 GW) but this increase could be mitigated to 30% (16 GW) by favourable conditions. DSM could reduce this increase to 20%, or 15% if used with extensive thermal storage. If 60% of dwellings use heat pumps, the increase in peak net-demand could be as low as 5.5 GW. High-performance heat pumps, appropriate installation and better insulated dwellings could make the increase in peak net-demand due to the electrification of heating more manageable.
Teng F, Aunedi M, Pudjianto D, et al., 2015, Benefits of demand-side response in providing frequency response service in the future GB power system, Frontiers in Energy Research, Vol: 3, ISSN: 2296-598X
The demand for ancillary service is expected to increase significantly in the future Great Britain (GB) electricity system due to high penetration of wind. In particular, the need for frequency response, required to deal with sudden frequency drops following a loss of generator, will increase because of the limited inertia capability of wind plants. This paper quantifies the requirements for primary frequency response and analyses the benefits of frequency response provision from demand-side response (DSR). The results show dramatic changes in frequency response requirements driven by high penetration of wind. Case studies carried out by using an advanced stochastic generation scheduling model suggest that the provision of frequency response from DSR could greatly reduce the system operation cost, wind curtailment, and carbon emissions in the future GB system characterized by high penetration of wind. Furthermore, the results demonstrate that the benefit of DSR shows significant diurnal and seasonal variation, whereas an even more rapid (instant) delivery of frequency response from DSR could provide significant additional value. Our studies also indicate that the competing technologies to DSR, namely battery storage, and more flexible generation could potentially reduce its value by up to 35%, still leaving significant room to deploy DSR as frequency response provider.
Trutnevyte E, Strachan N, Dodds PE, et al., 2015, Synergies and trade-offs between governance and costs in electricity system transition, Energy Policy, Vol: 85, Pages: 170-181, ISSN: 1873-6777
Affordability and costs of an energy transition are often viewed as the most influential drivers. Conversely, multi-level transitions theory argues that governance and the choices of key actors, such as energy companies, government and civil society, drive the transition, not only on the basis of costs. This paper combines the two approaches and presents a cost appraisal of the UK transition to a low-carbon electricity system under alternate governance logics. A novel approach is used that links qualitative governance narratives with quantitative transition pathways (electricity system scenarios) and their appraisal. The results contrast the dominant market-led transition pathway (Market Rules) with alternate pathways that have either stronger governmental control elements (Central Co-ordination), or bottom-up proactive engagement of civil society (Thousand Flowers). Market Rules has the lowest investment costs by 2050. Central Co-ordination is more likely to deliver the energy policy goals and possibly even a synergistic reduction in the total system costs, if policies can be enacted and maintained. Thousand Flowers, which envisions wider participation of the society, comes at the expense of higher investment and total system costs. The paper closes with a discussion of the policy implications from cost drivers and the roles of market, government and society.
Teng F, Pudjianto D, Strbac G, et al., 2015, Potential value of energy storage in the UK electricity system, Proceedings of the ICE - Energy, Vol: 168, Pages: 107-117, ISSN: 1751-4223
This paper assesses the value of distributed energy storage and informs the business case for its multiple applications in the UK electricity system. In contrast to earlier studies that focus on the benefits of energy storage for system operation and development, this work analyses the value that it may deliver to the owner. For this purpose, three models are proposed and applied to analyse the benefit of energy storage with applications in energy and ancillary service markets, revenue maximisation in the context of feed-in tariffs and reduction of carbon dioxide emissions. A large set of studies is carried out to quantify the commercial and emissions benefits of energy storage for those applications. Sensitivity analysis across various scenarios is performed to understand the key drivers for the value of energy storage and how it is affected by energy storage parameters and other factors such as network constraints, prices of energy and ancillary services, and inherent energy system characteristics. A review of current and near-term storage technology costs and functionality is also presented.
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