Publications
12 results found
Tam B, Babacan O, Kafizas A, et al., 2024, Comparing the net-energy balance of standalone photovoltaic-coupled electrolysis and photoelectrochemical hydrogen production., Energy Environ Sci, Vol: 17, Pages: 1677-1694, ISSN: 1754-5692
Photovoltaic-coupled electrolysis (PV-E) and photoelectrochemical (PEC) water splitting are two options for storing solar energy as hydrogen. Understanding the requirements for achieving a positive energy balance over the lifetime of facilities using these technologies is important for ensuring sustainability. While neither technology has yet reached full commercialisation, they are also at very different technology readiness levels and scales of development. Here, we model the energy balance of standalone large-scale facilities to evaluate their energy return on energy invested (ERoEI) over time and energy payback time (EPBT). We find that for average input parameters based on present commercialised modules, a PV-E facility shows an EPBT of 6.2 years and ERoEI after 20 years of 2.1, which rises to approximately 3.7 with an EPBT of 2.7 years for favourable parameters using the best metrics amongst large-scale modules. The energy balance of PV-E facilities is influenced most strongly by the upfront embodied energy costs of the photovoltaic component. In contrast, the simulated ERoEI for a PEC facility made with earth abundant materials only peaks at 0.42 after 11 years and about 0.71 after 20 years for facilities with higher-performance active materials. Doubling the conversion efficiency to 10% and halving the degradation rate to 2% for a 10-year device lifetime can allow PEC facilities to achieve an ERoEI after 20 years of 2.1 for optimistic future parameters. We also estimate that recycling the materials used in hydrogen production technologies improves the energy balance by 28% and 14% for favourable-case PV-E and PEC water splitting facilities, respectively.
Winkler L, Pearce D, Nelson J, et al., 2023, The effect of sustainable mobility transition policies on cumulative urban transport emissions and energy demand, NATURE COMMUNICATIONS, Vol: 14
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- Citations: 3
Sayani R, Ortega-Arriaga P, Sandwell P, et al., 2022, Sizing solar-based mini-grids for growing electricity demand: Insights from rural India, The Journal of High Energy Physics, Vol: 5, Pages: 1-26, ISSN: 1029-8479
Mini-grids are a critical way to meet electricity access goals according to current and projected electricity demand of communities and so appropriately sizing them is essential to ensure their financial viability. However, estimation of demand for communities awaiting electricity access is uncertain and growth in demand along with the associated cost implications is rarely considered during estimation of mini-grid sizing. Using a case study of two rural communities in India, we assess the implications of demand growth on financial costs and performance of a mini-grid system consisting of solar photovoltaic (PV) panels and battery storage using two different system sizing approaches. We show a cost-saving potential of up to 12% when mini-grids are sized using a multi-stage approach where mini-grids gradually expand in several stages, rather than a single-stage optimisation approach. We perform a sensitivity analysis of the cost of the two sizing approaches by varying six key parameters: demand growth rate, logistics cost, system re-sizing frequency, likelihood of blackouts, solar PV and battery cost, and degradation rate. Of these, we find that system costs are most sensitive to variations in demand growth rates and cost decreases in solar PV and batteries. Our study shows that demand growth scenarios and choice of mini-grid sizing approaches have important financial and operational implications for the design of systems for rural electrification.
Cilio L, Babacan O, 2021, Allocation optimisation of rapid charging stations in large urban areas to support fully electric taxi fleets, APPLIED ENERGY, Vol: 295, ISSN: 0306-2619
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- Citations: 14
Ortega-Arriaga P, Babacan O, Nelson J, et al., 2021, Grid versus off-grid electricity access options: A review on the economic and environmental impacts, Renewable and Sustainable Energy Reviews, Vol: 143, Pages: 1-17, ISSN: 1364-0321
This research reviews the economic and environmental impacts of grid-extension and off-grid systems, to inform the appropriate electrification strategy for the current population without electricity access. The principal technologies reviewed are centralised conventional fossil-fuel grid-extension and off-grid systems mainly based on solar PV and batteries. It finds that relatively few studies explicitly compare grid-extension electricity costs against off-grid systems costs and that there is a lack of consistency in the methodologies used to determine the least-cost solution. Nevertheless, the studies reviewed show a range of around $0.2–1.4/kWh for off-grid electricity access, compared to a range of below $0.1/kWh to more than $8/kWh for grid access, pointing to a number of cases in which off-grid access may already be the more cost-effective option. Existing literature on the environmental impacts primarily focuses on greenhouse gas emissions from electricity generation, with off-grid (solar PV and storage) systems’ emissions in the range of 50–130 gCO2-eq/kWh and grid generation from close to 0 gCO2-eq/kWh (for renewables and nuclear sources) to over 1,000 gCO2-eq/kWh (for coal). Emissions impacts stemming from transmission and distribution grids suggest a range of 0–30 gCO2-eq/kWh. Assessments of other environmental impacts such as water use, land use, biodiversity and e-waste are often absent in studies, whilst few studies explicitly compare the environmental impacts of grid versus off-grid systems. Further research should focus on comparing the costs of electricity access options using consistent metrics, expanding the scope of environmental impacts analysis, and integrating environmental and economic impacts into a comprehensive sustainability assessment of different options.
Moss B, Babacan O, Kafizas A, et al., 2021, A review of inorganic photoelectrode developments and reactor scale-up challenges for solar hydrogen production, Advanced Energy Materials, Vol: 11, Pages: 1-43, ISSN: 1614-6832
Green hydrogen, produced using solar energy, is a promising means of reducing greenhouse gas emissions. Photoelectrochemical (PEC) water splitting devices can produce hydrogen using sunlight and integrate the distinct functions of photovoltaics and electrolyzers in a single device. There is flexibility in the degree of integration between these electrical and chemical energy generating components, and so a plethora of archetypal PEC device designs has emerged. Although some materials have effectively been ruled out for use in commercial PEC devices, many principles of material design and synthesis have been learned. Here, the fundamental requirements of PEC materials, the top performances of the most widely studied inorganic photoelectrode materials, and reactor structures reported for unassisted solar water splitting are revisited. The main phenomena limiting the performance of up‐scaled PEC devices are discussed, showing that engineering must be considered in parallel with material development for the future piloting of PEC water splitting systems. To establish the future commercial viability of this technology, more accurate techno‐economic analyses should be carried out using data from larger scale demonstrations, and hence more durable and efficient PEC systems need to be developed that meet the challenges imposed from both material and engineering perspectives.
Abdulla A, Hanna R, Schell KR, et al., 2021, Explaining successful and failed investments in US carbon capture and storage using empirical and expert assessments, ENVIRONMENTAL RESEARCH LETTERS, Vol: 16, ISSN: 1748-9326
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- Citations: 24
Babacan O, De Causmaecker S, Gambhir A, et al., 2020, Assessing the feasibility of carbon dioxide mitigation options in terms of energy usage, Nature Energy, Vol: 5, Pages: 720-728, ISSN: 2058-7546
Measures to mitigate the emissions of carbon dioxide (CO2) can vary substantially in terms of the energy required. Some proposed CO2 mitigation options involve energy-intensive processes that compromise their viability as routes to mitigation, especially if deployed at a global scale. Here we provide an assessment of different mitigation options in terms of their energy usage. We assess the relative effectiveness of several CO2 mitigation routes by calculating the energy cost of carbon abatement (kilowatt-hour spent per kilogram CO2-equivalent, or kWh kgCO2e–1) mitigated. We consider energy efficiency measures, decarbonizing electricity, heat, chemicals and fuels, and also capturing CO2 from air. Among the routes considered, switching to renewable energy technologies (0.05–0.53 kWh kgCO2e–1 mitigated) offer more energy-effective mitigation than carbon embedding or carbon removal approaches, which are more energy intensive (0.99–10.03 kWh kgCO2e–1 and 0.78–2.93 kWh kgCO2e–1 mitigated, respectively), whereas energy efficiency measures, such as improving building lighting, can offer the most energy-effective mitigation.
Babacan O, Abdulla A, Hanna R, et al., 2018, Unintended Effects of Residential Energy Storage on Emissions from the Electric Power System, ENVIRONMENTAL SCIENCE & TECHNOLOGY, Vol: 52, Pages: 13600-13608, ISSN: 0013-936X
Babacan O, Ratnam EL, Disfani VR, et al., 2017, Distributed energy storage system scheduling considering tariff structure, energy arbitrage and solar PV penetration, Applied Energy, Vol: 205, Pages: 1384-1393, ISSN: 0306-2619
We develop a new convex optimization (CO)-based charge/discharge scheduling algorithm for distributed energy storage systems (ESSs) co-located with solar photovoltaic (PV) systems. The CO-based scheduling algorithm minimizes the monthly electricity expenses of a customer who owns an ESS and incorporates both a time-of-use volumetric tariff and a demand charge tariff. Further, we propose the novel idea of a “supply charge” tariff that incentivizes ESS customers to store excess solar PV generation that may otherwise result in reverse power flow in the distribution grid. By means of a case study we observe the CO-based daily charge/discharge schedules reduce (1) peak net demand (that is, load minus PV generation) of the customer, (2) power fluctuations in the customer net demand profile, and (3) the reliance of the customer on the grid by way of promoting energy self-consumption of local solar PV generation. Two alternate methods for behind-the-meter ESS scheduling are considered as benchmarks for cost minimization, peak net demand reduction, and mitigation of net demand fluctuations. The algorithm is tested using real 30-min interval residential load and solar data of 53 customers over 2-years. Results show that the CO-based scheduling algorithm provides mean peak net demand reductions between 46% and 64%, reduces mean net demand fluctuations by 25–49%, and increases the mean solar PV self-consumption between 24% and 39% when compared to a customer without an ESS. Introduction of a supply charge reduces the maximum solar PV power supply to the grid by 19% on average and does not financially impact ESS owners.
Bright JM, Babacan O, Kleissl J, et al., 2017, A synthetic, spatially decorrelating solar irradiance generator and application to a LV grid model with high PV penetration, SOLAR ENERGY, Vol: 147, Pages: 83-98, ISSN: 0038-092X
Babacan O, Torre W, Kleissl J, 2017, Siting and sizing of distributed energy storage to mitigate voltage impact by solar PV in distribution systems, SOLAR ENERGY, Vol: 146, Pages: 199-208, ISSN: 0038-092X
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