The future cost of electricity storage and its value in low-carbon power systems

The energy sector is transforming rapidly to reduce carbon emissions and limit global climate change. Electricity storage can provide the required flexibility to balance intermittent and relatively inflexible power generation with demand in low-carbon power systems. However, falling investment cost, the wide range of technologies with different performance characteristics and the wide range of use cases with different performance requirements lead to uncertainty on its commercial viability. To assess electricity storage against alternatives and enable further investment in low-carbon technologies, policy-makers and industry need certainty on cost reduction potentials and its value in enabling low-carbon power systems. This thesis creates an experience curve dataset for 11 electricity storage technologies, identifying investment cost reductions to US$325±125/kWh (systems) and US$155±45/kWh (packs) once 1 TWh capacity is installed for each technology. This could be achieved by 2027–2040 based on market growth projections. Expert interviews highlight the importance of production scale-up as cost reduction driver and provide a detailed list of technical and value chain innovations for two prominent storage technologies. The quantification of future application-specific lifetime cost with a novel, comprehensive formula, that accounts for all relevant cost and performance parameters, indicates that lithium ion will be the most cost competitive for most applications by 2030. Lower financing cost, in general, and performance improvements for alternative technologies specifically could challenge this dominance. Matching future lifetime cost to revenue potentials across applications reveals profitable business cases in three distinct application categories with specific requirements. An analysis of modelled flexibility capacity in power system studies reveals two approaches to assess electricity storage capacity requirements in low-carbon power systems. In both approaches, the flexibility capacity requirement relative to peak demand increases linearly with increasing wind, solar and nuclear penetration, albeit at different rates, requiring up to 65% or 115% in a fully decarbonised power system. These insights combined with the online availability of experience curve dataset and lifetime cost tool increase transparency on the future cost of electricity storage and its value in low-carbon power systems, supporting policy and industry in transforming the energy sector.Open Acces

Techno-Economic Evaluation of Long-Term Energy Storage Options for Variable Renewable Energies in South Africa.

Mechanical and Mechatronic Engineerin

A Techno-Economic Analysis of Lithium-Ion and Vanadium Redox Flow Batteries for Behind-the-Meter Commercial/Industrial Applications with a Focus on Achievable Efficiency and Degradation Rates.

This thesis concerns vanadium redox flow batteries (VRFB), and whether their posited advantages over the more commercially advanced lithium-ion battery (LIB) can translate to improved economic outcomes in realistic use-cases. The key advantage of the VRFB is increased lifetime; the energy storage medium (and major cost component) is simply two solutions of vanadium at differing oxidation states hence here is no scope for the myriad permanent degradation mechanisms that exist in LIB. As such, over a project lifetime VRFB will potentially have lower economic and environmental costs than LIB. A second posited advantage of the VRFB was the low incremental cost of storage duration, allowing longer durations to be more cost competitive. However, VRFB are disadvantaged by lower round-trip efficiency and a higher power capacity cost due to the relatively complex power generating apparatus. In this thesis, bottom up cost modelling for a state of the art VRFB predicted that following cost reductions in LIB over the last 5 years, the cost of incremental usable duration would now be very similar for the two technologies, negating one of the posited benefits. For the full cost-benefit analysis, it was hence important to rigorously define the use-cases and resulting cycle rates. The chosen case study was a commercial/industrial facility in South California. This region is a very promising market for stationary electrical storage, and as such was considered an arena in which VRFB and LIB are likely to compete in the near future. In order to thoroughly explore the thesis two differing archetypal use-case were formulated. In use-case A, the battery was called upon to reduce the electricity bill at the facility by time-shifting power imports to cheaper hours, reducing the peak power consumption each month, and generate revenue by providing spinning reserve and frequency response to the grid operator. The objective was strictly economic; to maximise the net present value of a ten year project. In use-case B, the battery was deployed in conjunction with a PV array in order to achieve self-sufficiency in power. In this case the self-sufficiency objective is in competition with the economic objective (to minimise the levelised cost of electricity), hence a multi-objective optimisation was used to size the battery and PV array. An important contribution made by this thesis was the incorporation of detailed degradation models for both VRFB and LIB. For VRFB, previous case studies had assumed zero degradation, whereas in practice regular intervention is required to avoid electrolyte imbalance. For LIB, similar case studies had employed models attributing all degradation to cycling, whereas continual temperature dependent aging is also important. The latter was modelled in this work. A novel mixed integer-quadratic programming (MIQP) method was introduced that allowed the VRFB operation to be optimised while accounting for the considerable variation in efficiency with power input/output. This is an improvement over previous VRFB case studies where a constant efficiency is assumed. In use-case A this resulted in the discovery of an energy saving strategy whereby the charging was performed at moderate power in order to track the peak efficiency as closely as possible. In a further novel contribution, this model was used to demonstrate the benefit of operating multiple VRFB modules as an ensemble. The benefit arises when a low load must be covered, and some modules may be idled to reduce parasitic losses. In use-case A, it was concluded that VRFB may compete with LIB under certain scenarios at 4 h duration, although the most profitable system is a shorter duration LIB. Both were predicted to break even at 6 h duration when current long duration storage incentives were included. For use-case B, both systems were predicted to achieve a SSR of 0.95 at under ¢21.5kW−1 h−1. Although the costs overlap depending on the scenario, VRFB were estimated to be more likely to be cheaper up to 0.9 SSR, above which reducing cycle rates favoured LIB. This level of self-sufficiency called for a usable duration of 6 h - 7.5 h. An important finding for project developers is hence that 6 h would be a sensible duration for both LIB and VRFB systems as this would cover both use cases effectively. Another novel contribution of this work to estimate the benefit of a hybrid LIB/VRFB system, the hypothesis being that the LIB could be used to cover the less frequent high charge/discharge power events. In use-case B this had the hypothesised effect of increasing the LIB lifetime, but there was negligible predicted effect on the overall levelised cost of electricity. Lastly, a number of important findings were made relating to practical operation of both LIB and VRFB, which should be of interest to asset owners. Firstly, in use-case A, it is unlikely that bidding for regulation provision would be feasible alongside demand charge reduction, as performing the former can result in a loss in the latter. Maintenance timing was predicted to be important for VRFB in use-case A where available revenue varies seasonally, and the capacity should be replenished prior to the peak revenue periods of the summer months. For LIB, it was predicted that managing state of charge will prolong life considerably in use-case B, and climactic variations across Southern California may strongly affect lifetime in both cases

Analysis of diabatic compressed air energy storage systems with artificial reservoir using the levelized cost of storage method

A detailed analysis has been carried out to assess the thermodynamic and economic performance of Diabatic Compressed Air Energy Storage (D-CAES) systems equipped with above-ground artificial storage. D-CAES plant arrangements based on both Steam Turbine (ST) and Gas Turbine (GT) technologies are taken into consideration. The influence of key design quantities (ie, storage pressure, turbine inlet pressure, turbine inlet temperature) on efficiency, capital and operating costs is analysed in detail and widely discussed. Finally, D-CAES design solutions are compared with Battery Energy Storage (BES) systems on the basis of the Levelized Cost of Storage (LCOS) method. Results show that the adoption of D-CAES can lead to better economic performance with respect to mature and emerging BES technologies. D-CAES ST based solutions can achieve a LCOS of 28 €cent/kWh, really close to that evaluated for the better performing BES system. Interesting LCOS values of 20 €cent/kWh have been attained by adopting D-CAES plant solutions based on GT technology

An assessment of flywheel storage for efficient provision of reliable power for residential premises in islanded operation

Energy storage systems (ESS) are key devices for improving power quality, electrical system stability and system efficiency by contributing to the balance of supply and demand. They can enhance the flexibility of electrical systems by mitigating supply intermittency, which has recently become problematic due to the increased penetration of renewable generation. The subject of this thesis is flywheel energy storage system (FESS), a technology that is gathering great interest due to benefits offered over alternative energy storage solutions, including high cycle life, long calendar life, high round‐trip efficiency, high power density, operation at high ambient temperatures and low negative environmental impact. This thesis describes the modelling and assessment of small scale energy system incorporating FESS with solar photovoltaic (PV) and a diesel generator for use in islanded residential premises with highly intermittent or non‐existent grid infrastructure. In this application, incorporation of FESS is shown to be beneficial in comparison to a system without storage or one with the alternative storage technology, Li‐Ion batteries. The thesis begins with a description of flywheel storage systems configured for electrical storage which comprises of a mechanical part; flywheel rotor, bearings and containment, and an electric drive part; motor‐generator and associated power electronics. Each of these components is described in the thesis along with the equations and modelling, itself carried out in the MATLAB/Simulink environment. Finally, the flywheel model is combined with a model of an islanded residential power system incorporating a solar PV system with a diesel generator. Such a system would be particularly useful for offgrid applications or those with weak grids as occurs in developing countries

Hybrid nuclear-solar power

Nuclear and solar power, in the form of concentrated solar power (CSP), play a significant role in achieving the ambitious global targets of reducing greenhouse emissions and guaranteeing security of energy supply. However, both power generation technologies still require further development to realise their full potential, especially in terms of attaining economic load following operations and higher thermal efficiencies. Therefore, the aim of this research is to investigate and thermo-economically evaluate the available options of upgrading the flexibility and enhancing the thermal efficiency of nuclear and solar power generation technologies (i.e., through the integration with thermal energy storage (TES) and by hybridising both power generation technologies) while providing reasonable economic returns. The thesis starts with describing the development and validation of several thermodynamic and economic computational models and the formulation of the whole-energy system model. The formulated models are utilised to perform several thermo-economic studies in the field of flexible nuclear and solar power, and to quantify the economic benefits that could result from enhancing the flexibility of nuclear power plants from the whole-energy system perspective. The studies conducted in this research are: (i) a thermo-economic assessment of extending the conventional TES system in direct steam generation (DSG) CSP plants; (ii) a thermo-economic evaluation of upgrading the flexibility of nuclear power plants by the integration with TES and secondary power generation systems; (iii) an investigation of the role of added flexibility in future low-carbon electricity systems; and (iv) a design and operation analysis of a hybrid nuclear-solar power plant. The most common TES option in DSC CSP plants is steam accumulation. This conventional option is constrained by temperature and pressure limits, leading to lower efficiency operations during TES discharging mode. Therefore, the option of integrating steam accumulators with sensible-heat storage in concrete to provide higher-temperature superheated steam is thermo-economically investigated in this research, taking an operational DSG CSP plant as a case study. The results show that the integrated concrete-steam TES (extended) option delivers 58% more electricity with a 13% enhancement in thermal efficiency during TES discharging mode, compared to the conventional steam accumulation (existing) configuration. With an estimated additional investment of $4.2M, the projected levelised cost of electricity (LCOE) and the net present value (NPV) for the considered DSG CSP plant with the extended TES option are respectively 6The option of upgrading the flexibility of nuclear power plants through the integration with TES and secondary power generation systems is investigated for two conventional nuclear reactors, a 670-MWel advanced gas-cooled reactor (AGR) and a 1610-MWel European pressurised reactor (EPR). In both investigated case studies, the reactors are assumed to continuously operate at full rated thermal power, while load following operations are conducted through the integrated TES tanks and secondary power generators. Based on the designed TES and secondary power generation systems, the AGR-based configuration can modulate the power output between 406 MWel and 822 MWel, while the EPR-based configuration can operate flexibly between 806 MWel and 2130 MWel. The economic analysis results demonstrate that the economics of added flexibility are highly dependent on: (i) the size of the TES and the secondary power generation systems; (ii) the number of TES charge/discharge cycles per day; and (iii) the ratio and difference between off-peak and peak electricity prices. Replacing conventional EPR-based nuclear power plants with added flexibility ones is found to generate whole-system cost savings between$30.4M/yr and $111M/yr. At an estimated cost of added flexibility of$53.4M/yr, the proposed flexibility upgrades appear to be economically justified with net system economic benefits ranging from $5.0M/yr and$39.5M/yr for the examined low-carbon scenarios, provided that the number of flexible nuclear plants in the system is small. The concept of hybridising a small modular reactor (SMR) with a solar-tower CSP integrated with two-tank molten salt TES system, with the aim of achieving economically enhanced load following operations and higher thermal efficiency levels, is also thermo-economically investigated in this research. The integration of both technologies is achieved by adding a solar-powered superheater and a reheater to a standalone SMR. The obtained results demonstrate that hybridising nuclear and solar can offer a great amount of flexibility (i.e., between 50% and 100% of nominal load of 131 MWel) with the SMR continuously operated at full rated thermal power output. Furthermore, the designed hybrid power plant is able to operate at higher temperatures due to the addition of the solar superheater, resulting in a 15% increase of thermal efficiency compared to nuclear-only power plant. Moreover, the calculated specific investment cost and the LCOE of the designed hybrid power plant are respectively 5410 $/kWel and 77$/MWhel, which are 2% and 4% lower than those calculated for the nuclear-only power plant.Open Acces

Techno-economic assessment and optimisation of a carnot battery application in a concentrating solar power plant.

Thesis (MEng)--Stellenbosch University, 2022.ENGLISH SUMMARY: The techno-economic assessment as well as optimisation of a Carnot battery application in a parabolic trough concentrating solar power (CSP) plant is conducted. A computational techno-economic model of the Carnot battery is developed and verified with reasonable accuracy. The model entails electric resistive heating integrated with the thermal energy storage of the CSP plant. During solar thermal charge cycles, potentially abundant solar photovoltaic grid electricity is stored as thermal energy. Stored energy is discharged during periods of lower solar thermal supply to promote baseload power generation. A fundamental techno-economic understanding of the CSP Carnot battery is developed. Charging costs, together with low round-trip efficiencies, can inhibit the system’s economic viability. Nonetheless, the CSP plant displays increased potential for baseload power generation once retrofitted. This enhances its continuity of inertial support and reduces intermittent power generation. The standard solar-thermal charge-discharge cycles are inherently suited for ideal time-shifting of surplus electricity, more so during summer than winter. Multi-objective optimisation determines the optimum thermal energy storage capacity for heater integration. The mathematical significance of optimisation results is explored via Pareto fronts and energy-cost curves. In general, the storage capacity is inversely related to the installed heater capacity at which the latter overcharges energy. At this point, electrical energy is stored at the expense of underutilised solar thermal energy. Plants with larger solar fields are more prone to overcharge, yielding less capacity for optimally allocated heaters. This could present a barrier to technical synergy.AFRIKAANS OPSOMMINGS: Die tegno-ekonomiese assessering sowel as optimisering van ’n Carnot-battery toepassing in ’n paraboliese trog gekonsentreerde sonkragaanleg (GSK) word uitgevoer. ’n Tegno-ekonomiese berekeningsmodel van die Carnot-battery word ontwikkel en as redelik akkuraat bevestig. Die model behels elektriese weerstandsverhitters wat met die aanleg se termiese energie-opbergingseenheid geïntegreer word. Vanuit die kragnetwerk word moontlike oortollige fotovoltaïese elektrisiteit tydens sontermiese laaisiklusse as termiese energie gestoor. Hierdie energie word tydens periodes van sontermiese onderverskaffing ontlaai, met die doel om basislading elektrisiteit op te wek. ’n Fundamentele tegno-ekonomiese begrip van die GSK Carnot-battery word ontwikkel. Laaikostes en lae omskakelingsdoeltreffendheid kan ekonomiese lewensvatbaarheid inhibeer. As ’n Carnot-battery toon die GSK-aanleg nietemin meer potensiaal vir basislading elektrisiteitsopwekking. Dit bevorder die kontinuïteit van traagheidsondersteuning en verminder afwisselende kragopwekking. Die standaard sontermiese laai-ontlaai siklusse is inherent gepas vir ideale tydverskuiwing van oortollige energie, veral meer tydens somer as winter. Meerdoelige optimisering word benut om die optimale termiese energie stoorkapasiteit vir verhitter toevoeging te bepaal. Die wiskundige betekenis van optimiseringsresultate word deur middel van Pareto-fronte en energie-koste kur-wes verken. In die algemeen is die stoorkapasiteit omgekeerd eweredig aan die verhitterkapasiteit waarby laasgenoemde energie oorlaai. Hier word elektriese energie ten koste van onderbenutte sontermiese energie gestoor. Aanlegte met groter sonvelde is meer vatbaar vir oorlading en bevat minder kapasiteit vir optimale verhitter integrasie. Hierdie eienskap kan tegniese sinergie bemoeilik.Master

Can Energy Storage Add Value to Future Urban Planning and Operation?

Residential electricity demand is expected to rise in the next few decades due to the electrification of heating and transportation. Both European and UK national policies suggest that efforts should be made to reduce carbon emissions and increase the share of renewable energy, an important element of which is encouraging generation, typically photovoltaic (PV), in partnership with energy storage systems in the residential sector. The scale of the energy storage system is important, with community energy storage (CES) and household energy storage (HES) being the two principal systems used in the residential sector. Many advantages of CES over HES have been identified, but the performance and impact on individual households within CES require further analysis. In this study an agent-based model is proposed to investigate and analyse CES based on a range of criteria. Results indicate that both HES and CES can significantly reduce the grid peak power import grid and export to the grid, improve the community self-consumption rate (SCR) and self-sufficiency rate (SSR), and contribute to much higher energy saving. Time-of-Use (TOU) tariffs can effectively shave peak demand and lower energy bills of households, but do not improve SCR and SSR. The economic feasibility of storage can be improved by 1) combining different services and tariffs to obtain more revenues for households; 2) more legislative and financial support to reduce system costs; and 3) more innovative business models and policies to optimise revenues with existing resource. Lastly, in order to encourage adoption of PV and storage, it is important to compare the UK to a country with successful applications and comprehensive policy support. The study therefore compares and contrasts CES in the UK and Germany. Results indicate that the primary impacting factor on SCR is solar generation. The results highlight the importance of using a location-specific approach for system planning. Households in Germany should aim to improve the utilisation of on-site generation by installing a larger storage system, whilst UK households should improve total renewable generation output, for example by using a hybrid PV plus wind turbine system. In addition, more financial and legislative support is needed in the UK to improve feasibility of HES and CES

Energy storage design and integration in power systems by system-value optimization

Energy storage can play a crucial role in decarbonising power systems by balancing power and energy in time. Wider power system benefits that arise from these balancing technologies include lower grid expansion, renewable curtailment, and average electricity costs. However, with the proliferation of new energy storage technologies, it becomes increasingly difficult to identify which technologies are economically viable and how to design and integrate them effectively. Using large-scale energy system models in Europe, the dissertation shows that solely relying on Levelized Cost of Storage (LCOS) metrics for technology assessments can mislead and that traditional system-value methods raise important questions about how to assess multiple energy storage technologies. Further, the work introduces a new complementary system-value assessment method called the market-potential method, which provides a systematic deployment analysis for assessing multiple storage technologies under competition. However, integrating energy storage in system models can lead to the unintended storage cycling effect, which occurs in approximately two-thirds of models and significantly distorts results. The thesis finds that traditional approaches to deal with the issue, such as multi-stage optimization or mixed integer linear programming approaches, are either ineffective or computationally inefficient. A new approach is suggested that only requires appropriate model parameterization with variable costs while keeping the model convex to reduce the risk of misleading results. In addition, to enable energy storage assessments and energy system research around the world, the thesis extended the geographical scope of an existing European opensource model to global coverage. The new build energy system model ‘PyPSA-Earth’ is thereby demonstrated and validated in Africa. Using PyPSA-Earth, the thesis assesses for the first time the system value of 20 energy storage technologies across multiple scenarios in a representative future power system in Africa. The results offer insights into approaches for assessing multiple energy storage technologies under competition in large-scale energy system models. In particular, the dissertation addresses extreme cost uncertainty through a comprehensive scenario tree and finds that, apart from lithium and hydrogen, only seven energy storage are optimizationrelevant technologies. The work also discovers that a heterogeneous storage design can increase power system benefits and that some energy storage are more important than others. Finally, in contrast to traditional methods that only consider single energy storage, the thesis finds that optimizing multiple energy storage options tends to significantly reduce total system costs by up to 29%. The presented research findings have the potential to inform decision-making processes for the sizing, integration, and deployment of energy storage systems in decarbonized power systems, contributing to a paradigm shift in scientific methodology and advancing efforts towards a sustainable future