Assessing the Design and Operation of Redox Flow Batteries through Levelized Cost Analysis
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Energy storage is expected to play an important role in enabling deep decarbonization of the electric sector by addressing the intermittencies of renewable power generation 1 . The redox flow battery (RFB) is a potential energy storage solution whose unique decoupling of energy and power make it increasingly competitive, on a capital cost basis, at longer discharge durations 2 . While the capital cost benefits to RFBs are well-described in the literature 3 , there are additional economic benefits associated with operation and maintenance of open systems (e.g., tune-ups, sparing strategies) 4 as compared to closed systems like lithium-ion batteries. For example, crossover, undesirable species transport through the semi-permeable membrane that separates the positive and negative electrolytes, leads to comparatively rapid capacity fade in RFBs 5 but can be remediated via electrolyte rebalancing, replacement, or other servicing, all of which can be performed without sacrificing or altering the reactor components. The costs necessary to maintain battery performance over time impact its economic viability, but are not captured in the conventional capital cost estimations 6 . This motivates the development of techno-economic models that consider the variable operating principles of different battery formats and chemistries. In this presentation, we describe a simple levelized cost of storage (LCOS) model for RFBs that captures long-term performance changes and maintenance costs by including capacity fade and recovery 7 . We use this model to assess the impact of different design and operational decisions on RFB cost. Specifically, we contemplate different chemistries (symmetric vs. asymmetric, finite lifetime vs. infinite lifetime), operating strategies (e.g., rebalancing schedule), performance improvements (e.g., reducing fade rates), design decisions (e.g., battery sizing), and investment approaches (e.g., electrolyte leasing). We find that there are tradeoffs in capital and operating expenses, and in many cases upfront investments pay off in long-term savings. We anticipate this analysis will provide new insights into the cost-drivers for RFBs and motivate further research efforts in the evaluation and development of new chemistries, component materials, and reactor configurations. Acknowledgements We gratefully acknowledge funding from the MIT Energy Initiative. References Intergovernmental Panel on Climate Change. Global Warming of 1.5 C . https://www.ipcc.ch/sr15/ (2018). Darling, R. M., Gallagher, K. G., Kowalski, J. A., Seungbum, H. & Brushett, F. R. Pathways to low-cost electrochemical energy storage: a comparison of aqueous and nonaqueous flow batteries. Energy Environ. Sci. 7 , 3459–3477 (2014). Viswanathan, V. et al. Cost and performance model for redox flow batteries. J. Power Sources 247 , 1040–1051 (2014). Yuan, X.-Z. et al. A review of all-vanadium redox flow battery durability: Degradation mechanisms and mitigation strategies. Int. J. Energy Res. 1–40 (2019) doi:10.1002/er.4607. Prifti, H., Parasuraman, A., Winardi, S., Lim, T. M. & Skyllas-Kazacos, M. Membranes for redox flow battery applications. Membranes vol. 2 275–306 (2012). US Department of Energy. Grid Energy Storage . https://www.energy.gov/sites/prod/files/2014/09/f18/Grid Energy Storage December 2013.pdf (2013). Rodby, K. E. et al. Assessing the levelized cost of vanadium redox flow batteries with capacity fade and rebalancing. J. Power Sources 460 , 227958 (2020).Keywords:
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We update the cost of nuclear power as calculated in the MIT (2003) Future of Nuclear Power study. Our main focus is on the changing cost of construction of new plants. The MIT (2003) study provided useful data on the cost of then recent builds in Japan and the Republic of Korea. We provide similar data on later builds in Japan and the Republic of Korea as well as a careful analysis of the forecasted costs on some recently proposed plants in the US. Using the updated cost of construction, we calculate a levelized cost of electricity from nuclear power. We also update the cost of electricity from coal- and gas-fired power plants and compare the levelized costs of nuclear, coal and gas. The results show that the cost of constructing a nuclear plant have approximately doubled. The cost of constructing coal-fired plants has also increased, although perhaps just as importantly, the cost of the coal itself spiked dramatically, too. Capital costs are a much smaller fraction of the cost of electricity from gas, so it is the recent spike in the price of natural gas that have contributed to the increased cost of electricity. These results document changing prices leading up to the current economic and financial crisis, and do not incorporate how this crisis may be currently affecting prices.
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Economic cost is decisive for the development of different power generation. Life cycle cost (LCC) is a useful tool in calculating the cost at all life stages of electricity generation. This study improves the levelized cost of electricity (LCOE) model as the LCC calculation methods from three aspects, including considering the quantification of external cost, expanding the compositions of internal cost, and discounting power generation. The improved LCOE model is applied to three representative kinds of power generation, namely, coal-fired, biomass, and wind power in China, in the base year 2015. The external cost is quantified based on the ReCiPe model and an economic value conversion factor system. Results show that the internal cost of coal-fired, biomass, and wind power are 0.049, 0.098, and 0.081 USD/kWh, separately. With the quantification of external cost, the LCCs of the three are 0.275, 0.249, and 0.081 USD/kWh, respectively. Sensitivity analysis is conducted on the discount rate and five cost factors, namely, the capital cost, raw material cost, operational and maintenance cost (O&M cost), other annual costs, and external costs. The results provide a quantitative reference for decision makings of electricity production and consumption.
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This work presents a very detailed techno-economic analysis of the technology, made up of two complementary models. A performance model implemented in Thermoflex environment is used to explore alternative integration layouts in order to enable the simultaneous operation on solar and fossil energy. Then, a detailed cost analysis calculates the capital and operation costs of the plant from the engineering, procurement and construction standpoints. These two models are then combined in annual simulations to obtain the final levelized cost of electricity (LCoE) from which a solid conclusion about the true potential of solar gas turbines can be ascertained. A sensitivity analysis with respect to the main boundary conditions is also provided. The results confirm that LCoE in the order of 14 c€/kWh can be obtained when running the plant during sun hours (daily operation), yielding almost 70% annual solar share and for a fuel cost of 8 €/MBTU. In a higher fuel cost scenario (12 €/MBTU), this cost rises to almost 17 c€/kWh whereas it decreases to 10.5 c€/kWh if fuel costs are 4 €/MBTU. The different sensitivity analyses performed highlight the very strong regional effect on LCoE, not only for direct normal irradiance (DNI) but also for the largely variable local labor costs.
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Sudan faces an electricity supply shortage despite its abundant natural resources. This paper aims to manage these resources for sustainable power generation to meet Sudan’s electricity demand. The sustainability assessment integrates quantitative analysis of power generation’s impacts on water, land, and greenhouse gas (GHG) emissions, in addition to the levelized cost of electricity (LCOE). Cost-effective, resource- and GHG emission-effective, and GHG-stringent scenarios are executed in this study to investigate the impact of different constraints on the sustainability of power generation in Sudan. The average LCOEAV for these three scenarios is 43.64–100.00 USD/MWh, with the lowest in the cost-effective scenario and the highest in the resource- and GHG emission-effective scenario. The LCOEAV for the stringent scenario is 32% higher than the cost-effective scenario. The two governmental and lowest-cost plans, which serve as the business-as-usual cases in this study, are optimized and comparatively evaluated. The sensitivity analysis is conducted by reducing each clean energy pathway to a minimum LCOE of 42.89 USD/MWh. Solar–photovoltaic (PV), wind, and hydroelectricity pathways are the most sensitive to the LCOE and can significantly contribute to Sudan’s total power generation if their costs are minimal. A rational scenario for power generation in Sudan is developed to improve sustainability performance and avoid the unreliability of the studied scenarios and cases. The rational average generation mix comprises 44% clean energy, 46% fossil fuels, and 10% imported electricity pathways.
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The US Department of Energy Geothermal Technologies Office (DOE-GTO) has developed the tool Geothermal Electricity Technologies Evaluation Model (GETEM) to assess the levelized cost of electricity (LCOE) of power produced from geothermal resources. Recently modifications to GETEM allow the DOE-GTO to better assess how different factors impact the generation costs, including initial project risk, time required to complete a development, and development size. The model characterizes the costs associated with project risk by including the costs to evaluate and drill those sites that are considered but not developed for commercial power generation, as well as to assign higher costs to finance those activities having more risk. This paper discusses how the important parameters impact the magnitude project costs for different project scenarios. The cost distributions presented include capital cost recovery for the exploration, confirmation, well field completion and power plant construction, as well as the operation and maintenance (O&M) costs. The paper will present these cost distributions for both EGS and hydrothermal resources.
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Electrolyte imbalance is the main cause of capacity loss in vanadium redox flow batteries. It has been widely reported that imbalance caused by vanadium crossover can be readily recovered by remixing the electrolytes, while imbalance caused by a net oxidation of the electrolyte can only be reverted by means of more complex chemical or electrochemical methods. At the moment, however, the joint effect of both types of imbalances on the battery capacity is still not well understood. To overcome this limitation, generalised State of Charge and State of Health indicators that consider both types of imbalances are derived in this work. Subsequently, a thorough analysis on how the battery capacity depends on electrolyte imbalance is performed. As a result of this analysis, two specific outcomes are highlighted. Firstly, it is shown that standard electrolyte remixing may be counterproductive under certain imbalance conditions, further reducing the battery capacity instead of augmenting it. Secondly, it is demonstrated that most of the capacity loss caused by oxidation can be mitigated by inducing an optimal mass imbalance in the system. Consequently, a systematic procedure to track this optimum is proposed and validated through computer simulation.
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Flow battery
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