Renewable Electricity System Research Articles

Renewable sources-based efficient electric vehicle charging system through power forecasting and charge scheduling

Renewable sources-based efficient electric vehicle charging system through power forecasting and charge scheduling

Optimising Portugal’s 2050 energy system: Electric vehicles and hydrogen integration using Grey Wolf Optimiser and EnergyPLAN

The global shift to sustainable energy, driven by climate concerns and energy security, is backed by worldwide governmental commitments to reduce greenhouse gas emissions and enhance renewable energy sources in the energy systems. In 2016, the Portuguese Government pledged to carbon neutrality by 2050 as part of this global effort. This article proposes technical solutions for reducing carbon dioxide emissions and increasing renewable energy in the Portuguese mainland energy system by 2050, considering the targets set by the government. An energy system modelling approach based on the Grey Wolf Optimiser and the EnergyPLAN software was introduced. Seven scenarios for 2050 assess the impacts of transport electrification and hydrogen grid integration while minimising costs and/or carbon dioxide emissions. The results show that achieving a nearly 100% renewable electricity system and carbon neutrality is possible, considering a carbon capture ranging from 2.65Mt to 5.87Mt. The 2050 energy system requires a minimum battery storage of 5.1GWh and a minimum natural gas storage of 2,063GWh. Transport electrification requires an increase in the total installed capacity by at least 1.83GW, while hydrogen integration increases it by a minimum of 8.25GW. Developing interconnection capacity beyond 15% of the total installed capacity is crucial for grid stability and reducing fossil fuel dependence.

Environmental flows in a future climate: Balancing hydropower production and ecosystem rehabilitation in the Ume River system, Sweden

Hydropower is central to renewable electricity systems, but degrades ecosystems, calling for environmental flow schemes to enhance the ecological status of river systems. Environmental flow assessments need to account for climate change, since climate-driven changes in runoff affect both hydropower operation and riverine ecosystems. Here, we quantify expected changes in hydropower production and environmental benefits of introducing environmental flows in a large regulated river system in northern Sweden in a future climate. Compared with the hydrology of 1981–2010, runoff is projected to increase with climatic conditions projected for 2040, leading to a 2.2 % increase in hydropower production with present rules for turbine and reservoir operation. Implementing environmental flows will result in lower hydropower production losses in with the 2040 climate than at present: Introducing restrictions against zero flow events, discharge to technical fishways and bypassed reaches throughout the year (with seasonal flow variation), as well as having more natural water-level variation in all run-of-river impoundments, would reduce annual hydropower production with 3.5 % with present conditions, and by 3.3 % in 2040. At the same time, the net effect of higher runoff and introducing environmental flows means that the annual hydropower production in the 2040 climate would be only 0.8 % lower compared to 1981–2010. In all scenarios, reservoir filling degree in 2040 was projected to increase compared to scenarios for 1981–2010, and flow requirements were met for both environmental flows and hydropower production over an 83-year scenario-based time series. This study demonstrates the feasibility of introducing environmental flow actions in Sweden, and other regions where increases in runoff are projected, with sustained hydropower production, having large benefits for riverine biodiversity and enhancing resilience of riverine ecosystems to climate change. For this to be successful, collaboration among stakeholders in riverine management is needed.

Electricity system optimisation based on python model for renewable electricity generation portfolio

100% renewable electricity scenarios have received great attention from industry and policy makers, this is due to its widespread need for technical, economical, and renewable integration action plans. In this research, a python model named WIBSS, is developed and tested for adequacy using sensitivity analysis and then used to simulate the Irish electricity system.In this investigation, the optimal cost was identified with the installed capacities needed for the electricity system for high electricity demand scenario, and the generation portfolios for the electricity system in Ireland is proposed.The electricity system parameters are determined and the levelised cost of electricity is optimised and tabulated. In this investigation, the optimal solution is identified to decrease curtailment and minimize the total cost. Overlay graphs are plotted, and the optimal renewable sources combinations are presented.This research of determining generation portfolios toward 100% renewable electricity systems demonstrates simulations of two different pathways for 2030 scenarios to meet electricity demand in Republic of Ireland. The renewable energy target appeared in the government climate action plan and the authors renewable energy target determined based on the simulation of the python model, with more than doubled photovoltaic installation, a significant reduction in offshore wind, and a substantial integration of battery capacity, the authors renewable energy target performs better than renewable energy target, the levelised cost of electricity were 57.22 €/mWh and 51.11 €/mWh respectively. The least cost pathway is extended to balance between electricity generation and electricity demand in 2040 scenario, and keys target were proposed for generation portfolios.

Oahu as a case study for island electricity systems relying on wind and solar generation instead of imported petroleum fuels

A macro-scale electricity model was used to evaluate whether wind and solar generation, combined with short- and long-duration energy storage, could cost-effectively provide 100% of Oahu's electricity. A least-cost renewable electricity system was developed with 100% of hourly averaged demand met, based on 14 consecutive years of hourly wind and solar resource and electricity demand data. The system used current asset costs for wind generation, solar generation, short-duration battery storage, and long-duration hydrogen energy storage. Our results indicate that Oahu could transition to an electricity system reliant on wind and solar generation and battery and hydrogen storage with electricity costs lower than today's electricity costs. For Oahu, a least-cost wind-solar-battery electricity system that would have met 100% of hourly averaged demand would have a system cost of $0.2458 per kWh. In comparison, from October 2022 through September 2023, electricity generation costs from the petroleum-dominated electricity system on Oahu were between $0.2126/kWh and $0.2987/kWh. This wind-solar-battery system would require 332 km2 (21.4%) of Oahu's land. Moreover, including hydrogen storage as a second form of energy storage led to reductions in system cost and land use. At current asset costs, a least-cost wind-solar-battery‑hydrogen electricity system that would have met 100% of hourly averaged demand would have a system cost of $0.1673/kWh and require 265 km2 (17.1%) of Oahu's land. This case study indicates that other isolated regions with similar resource profiles and a reliance on imported petroleum fuels could realize a decrease in electricity system costs when switching to renewables in conjunction with short- and long-duration energy storage, at current asset costs, while meeting demand in full over extended periods of renewable resource variability.

Identification and application of indicators for the assessment of pumped hydro storage projects with renewable energy generation

Pumped hydro storage is crucial in Europe's energy strategy to achieve a 100% renewable energy-based electricity system by 2050. As a consequence of the large number of factors involved and the variety of criteria included in a proper assessment of renewable generation projects with pumped hydro storage, this paper aims to identify and calculate technical, economic, environmental and social indicators in order to provide a tool to improve the decision-making process in this type of large-scale projects.

Impact of demand growth on the capacity of long-duration energy storage under deep decarbonization

Abstract The weather-dependent uncertainty of wind and solar power generation presents a challenge to the balancing of power generation and demand in highly renewable electricity systems. Battery energy storage can provide flexibility to firm up the variability of renewables and to respond to the increased load demand under decarbonization scenarios. This paper explores how the battery energy storage capacity requirement for compressed-air energy storage (CAES) will grow as the load demand increases. Here we used an idealized lowest-cost optimization model to study the response of highly renewable electricity systems to the increasing load demand of California under deep decarbonization. Results show that providing bulk CAES to the zero-emission power system offers substantial benefits, but it cannot fully compensate for the 100% variability of highly renewable power systems. The capacity requirement of CAES increases by ≤33.3% with a 1.5 times increase in the load demand and by ≤50% with a two-times increase in the load demand. In this analysis, a zero-emission electricity system operating at current costs becomes more cost-effective when there is firm power generation. The least competitive nuclear option plays this role and reduces system costs by 16.4%, curtails the annual main node by 36.8%, and decreases the CAES capacity requirements by ≤80.7% in the case of a double-load demand. While CAES has potential in addressing renewable variability, its widespread deployment is constrained by geographical, societal, and economic factors. Therefore, if California is aiming for an energy system that is reliant on wind and solar power, then an additional dispatchable power source other than CAES or similar load flexibility is necessary. To fully harness the benefits of bulk CAES, the development and implementation of cost-effective approaches are crucial in significantly reducing system costs.

Diurnal Asymmetry Effects of Photovoltaic Power Plants on Land Surface Temperature in Gobi Deserts

The global expansion of photovoltaic (PV) power plants, especially in ecologically fragile regions like the Gobi Desert, highlights the suitability of such areas for large-scale PV development. The most direct impact of PV development in the Gobi Desert is temperature change that results from the land-use-induced albedo changes; however, the detailed and systemic understanding of the effects of PV expansion on land surface temperature remains limited. This study focuses on the 16 largest PV plants in the Chinese Gobi Desert, utilizing remote sensing data to assess their effects on land surface temperature. Our result showed a cooling effect during the daytime (−0.69 ± 0.10 °C), but a warming effect during the nighttime (0.23 ± 0.05 °C); the overall effect on the daily mean was a cooling effect (−0.22 ± 0.05 °C). Seasonal variations were observed, with the most significant cooling effect in autumn and the weakest in summer. The PV area was the most significant factor which influenced the temperature variation across PV plants. Our findings enrich our understanding of the environmental effects arising from the construction of PV plants and provide vital information for the design and management of increasingly renewable electricity systems globally.

CONCEPTUAL MODEL OF A NANOSATELLITE WITH LASER BEAM TRANSMISSION AND ITS IMPORTANCE IN RENEWABLE ELECTRICAL POWER HARVESTING

The concept of placing huge solar-powered satellite systems (SPS) in space represents one of several new technology options that could provide large-scale, green base power to terrestrial markets. NASA has already launched the multi-megawatt SSP systems and wireless power transmission (WPT) for government missions and commercial markets (in space and on the ground). In the new space approach satellite technology Nanosatellites with benefits such as low price, resource use, and compatibility with COTS, have huge potential to be the next generation of renewable electrical solar power harvesting satellite systems. With that in mind, it is important to conduct research and development processes for achieving high-efficiency satellite systems. As a result, an initial conceptual model of the new generation low earth orbit nanosatellite with solar power harvesting to laser beam conversion and transmission sub-system was developed with an estimated solar radiation harvesting calculus, part selection along with the structural scheme and its working principle have been proposed.

Paving the way: Analysing energy transition pathways and green hydrogen exports in developing countries – The case of Algeria

The measures needed to limit global warming pose a particular challenge to current fossil fuel exporters, who must not only decarbonise their local energy systems, but also compensate for the expected decline in fossil fuel revenues. One possibility is seen in the export of green hydrogen. Using Algeria as a case study, this paper analyses how different levels of ambition in hydrogen exports, energy efficiency and fuel switching affect the cost-optimal expansion of the power sector for a given overall emissions reduction path. Despite falling costs for photovoltaics and wind turbines, the results indicate that in countries with very low natural gas prices, such as Algeria, a fully renewable electricity system by 2050 is unlikely without appropriate policy measures. The expansion of renewable energy should therefore start early, given the high annual growth rates required, which will be reinforced by additional green hydrogen exports. In parallel, energy efficiency is a key factor as it directly mitigates CO2 emissions from fossil fuels and reduces domestic electricity demand, which could instead be used for hydrogen production. Integrating electrolysers into the power system could potentially help to reduce specific costs through load shifting. Overall, it seems advisable to analyse hydrogen exports together with local decarbonisation in order to better understand their interactions and to reduce emissions as efficiently as possible. These results and the methodology could be transferred to other countries that want to become green hydrogen exporters in the future and are therefore a useful addition for researchers and policy makers.

The role of regional renewable energy integration in electricity decarbonization—A case study of Japan

Decarbonization strategies depend critically on the integration of region-specific renewable energy and social acceptance, yet their roles still need to be clarified. This study designs a regional-integrated electricity system and assesses the impact of regional decisions associated with renewable energy on cost-effective national decarbonization, using Japan as a case study owing to its active engagement in regional decarbonization. A high spatial resolution renewable electricity system model that explicitly considers all 1741 Japanese municipalities and employs a hierarchical optimization approach is developed. Based on the model, the opportunity cost of limiting renewable energy development is quantified for 30 representative municipalities. The results highlight that restrictions on municipal renewable energy can increase annual system costs by hundreds of millions of euros and national electricity costs by up to 0.4%, although it varies by region and energy source. This suggests that widespread opposition to renewables could be a significant barrier to cost-effective decarbonization. However, the impact of solar photovoltaic (PV) tends to be slight. In conclusion, investments in social acceptance of region-specific renewables can minimize opportunity losses and reduce system costs. Nonetheless, relocating the project to another region is possibly more cost-effective for solar PV.

Physically 100 % renewable electricity supply through hybrid electricity storage – A top-down modelling study for the case of Austria

A top-down model calculation based on real generation and demand data is presented for the hypothetical case of 100 % renewable electricity generation combined with hybrid electricity storage infrastructure in the Austrian control area (9 million inhabitants, electric demand ∼70 TWh per year). To reach 100 % physical coverage by renewables, the actual wind and photovoltaic generation curves in the selected reference year of 2022 were scaled by a factor of 2.8 and 30, respectively. In the scope of the presented system are lithium-ion battery storage (cyclic efficiency 90 %), pumped hydro storage (70 %) and power-to-gas storage with subsequent re-electrification in gas turbine combined cycle plants operated as combined heat and power (CHP) system (30 %). Our core aspect lies in the optimized operation of the hybrid storage system, where the charging and discharging of the storage technology with higher cyclic efficiency is given priority. A straightforward cascading control algorithm is applied with individual elements functioning as simple proportional controllers. The results show how a 100 % renewable electricity system in Austria could be configured, partially building upon existing electricity generation infrastructure (pumped hydro and gas turbine combined cycle plants) and on the implementation of new lithium-ion battery storage with a total capacity of 100 GWh and new electrolysis infrastructure with a power of 5 to 10 GW. To overcome existing limitations of the presented model, an extension to a more complex model with spatial differentiation and consideration of electricity grid characteristics and constraints is recommended.

Techno-Economic Comparison of Electricity Storage Options in a Fully Renewable Energy System

To support increasing renewable capacity for a net-zero future, energy storage will play a key role in maintaining grid stability. In this paper, all current and near-future energy storage technologies are compared for three different scenarios: (1) fixed electricity buy-in price, (2) market-based electricity buy-in price, and (3) energy storage integrated into a fully renewable electricity system. In the first part of this study, an algorithm is devised to simulate strategic buy-in of electricity for energy storage. This analysis yields a qualitative decision-making tool for a given energy storage duration and size. Building upon the first part’s findings, an integration study gives insight into expected power prices and expected storage size in a typical northwestern European fully renewable energy system. The integration study shows significant need for electricity storage with durations spanning from one to several days, typically around 40 h. Pumped Hydro Storage and Pumped Thermal storage surface as the best options. The overall levelized costs of storage are expected to be in the USD 200–500/MWh range. Integration of storage with renewables can yield a system-levelized cost of electricity of about USD 150/MWh. Allowing flexibility in demand may lower the overall system-levelized cost of electricity to USD 100/MWh.

Transformation to a renewable electricity system in Austria: Insights from an integrated model analysis

We analyse the (techno- and macro-)economic and distributive effects of a transformation to a renewable electricity system in Austria by 2030, as stipulated by the Austrian government. For the analysis, the macroeconomic model DYNK and ATLANTIS, a partial model of the electricity market, were expanded and linked. Four transformation scenarios conforming with the 100% renewable electricity target in Austria on a national balance are examined, integrated into a consistent scenario for the development of the European electricity system. Additionally, sensitivity analyses with respect to the gas price are performed. Although all scenarios achieve 100% renewable electricity on a national balance, the analysis shows that electricity from gas-fired power plants will still be needed in 2030 to balance variable renewable generation, to avoid grid congestion, and for heat generation from combined heat and power plants in winter months. Another main conclusion from the simulations is that the transition towards a renewable electricity sector is almost neutral from a socio-economic perspective. It does neither reveal harmful impacts nor lead to high multiplier effects from additional investment. With high natural gas prices in the sensitivity scenarios a decrease in GDP and household income, which might motivate redistributive policies, can be observed.

How Do Governments’ Policy Priorities Change as the Energy Transition Progresses? A Cross-Country Comparison

Today’s energy transition is marked by two key processes: the maturation of the renewable electricity system, and the declining fit between the new and incumbent electricity systems. Given these processes, how do governments change their policy priorities as the transition progresses? Our comparative analysis of six EU member states shows that governments dynamically adapt their policy priorities based on changes in their socio-technical systems. Our initial findings suggest that governments follow a specific sequence of policy priorities in the energy transition. Results stress how important it is that governments strategically sequence policy instruments for a smooth transition amid changing priorities.

Evaluating the impact of passenger electric vehicle adoption on high renewable resources electricity grid

A considerable amount of electricity is additionally demanded for Electric Vehicle (EV) charging due to rapid EV penetration. This study explores the impact of time of charging for different levels of passenger EV penetration on the electricity system using a case study electricity system with high penetration of renewable energy resources. A simulation approach is proposed to determine the new demand profile due to EV charging. Next, a Mixed Integer Linear Programming model is formulated considering the operation schedules of conventional power plants to mimic the real-time status of the electricity system. Finally, the developed approach considers the different possible interventions of actual EVs available in the market and tries to determine their impact in a renewable energy-dominated electricity system. The results from the study show that it is emission-friendly to encourage night charging rather than day charging for the considered renewable energy-dominated case study electricity system.

Renewable Electric Energy System Planning Considering Seasonal Electricity Imbalance Risk

The growing renewable integration significantly enhances the seasonal electricity imbalance of the electric energy system. However, traditional power system planning methods usually take into account the hourly power balance within typical days but seldom consider the seasonal imbalance risk in the long-term timescale. Therefore, this paper proposes a generation-transmission-storage co-planning model considering the seasonal imbalance risk brought by the long-term uncertainty of renewable generation in the power system. The Conditional Value at Risk (CVaR) method is introduced to quantify the seasonal imbalance risk. The power system energy balance constraints are decoupled into short-term (i.e., hourly) and long-term (i.e., monthly) energy balance so that the operation of the power system can be considered within different timescales and the seasonal imbalance risk could be calculated. The validity of the proposed model is first investigated via a modified Garver's 6-bus system case study. Furthermore, the research on the HRP-38 system (HRP represents high renewable penetration) illustrates that our proposed model could effectively control the energy imbalance risk from multiple timescales. Finally, the proposed method is applied to the whole China power system at the province level, proving that the proposed planning method could effectively enhance the reliability of China's power system, decreasing both the average annual short-term and long-term energy imbalance by 30%.

Prospective life cycle environmental impact assessment of renewable energy-based methanol production system: A case study in China

Integrating renewable electricity and green hydrogen with CO2 utilization to produce chemicals has drawn much attention due to its low carbon emission characteristics. The goal of this paper is to investigate the environmental sustainability of producing a steady hourly output of methanol by utilizing electricity and hydrogen produced via renewable energy resources, and CO2 captured from a coal-fired power plant located in Inner Mongolia, China. Six renewable energy-based electricity and hydrogen systems are considered based on photovoltaic, wind turbines and combinations thereof, including battery and grid technologies. The environmental impact indicators of these system are compared comprehensively through life cycle assessment approach, including not only global warming potential but also fossil fuel depletion, water & soil & air pollution indices and human health index. The results indicate that the most environmentally friendly system is Case B2 which uses photovoltaic to produce hydrogen and electricity, with battery for energy storage and excess electricity sold back to grid. It shows apparently the best sustainability performance in global warming potential, which is 0.105 kg CO2-eq per kg methanol. In general, the proposed six systems outperform conventional methanol production systems in terms of global warming potential and abiotic depletion potential, with reductions ranging from 74% to 92% and 51.1%–73.8% respectively, but they have high levels in other environmental sustainability indicators such as human toxicity, eutrophication potential, and ozone layer depletion potential due to the photovoltaic electricity generation unit. The findings highlight that it is essential to consider a comprehensive range of environmental sustainability indicators when developing renewable energy-based methanol systems on a large scale.

Renewable electricity capacity planning with uncertainty at multiple scales

We formulate and compare optimization models of investment in renewable generation using a suite of social planning models that compute optimal generation capacity investments for a hydro-dominated electricity system where inflow uncertainty results in a risk of energy shortage. The models optimize the expected cost of capacity expansion and operation allowing for investments in hydro, geothermal, solar, wind, and thermal plant, as well as battery storage for smoothing load profiles. A novel feature is the integration of uncertain seasonal hydroelectric energy supply and short-term variability in renewable supply in a two-stage stochastic programming framework. The models are applied to data from the New Zealand electricity system and used to estimate the costs of moving to a 100% renewable electricity system by 2035. We also explore the outcomes obtained when applying different forms of CO2 constraint that limit respectively non-renewable capacity, non-renewable generation, and CO2 emissions on average, almost surely, or in a chance-constrained setting, and show how our models can be used to investigate the merits of a proposed pumped-hydro scheme in New Zealand’s South Island.

An inexact fractional multi-stage programming (IFMSP) method for planning renewable electric power system

The growing levels of greenhouse gas (GHG) emissions have made renewable energy sources a crucial aspect of power generation, especially in developing countries. However, with more investment in additional renewable energy components and the mandatory decommissioning requirement of the thermal stations, the uncertainty of renewable energy availability and the changeable policy environment have brought great complexity to the electric power systems. Hence, an innovative approach, the inexact fractional multistage programming (IFMSP), has been proposed to address the challenges of electric power system planning in transitioning to clean energy, specifically in South Africa from 2021 to 2050. The IFMSP approach balances economic benefits and GHG emission mitigation, providing a more constrained optimum interval solution than binary integer programming. The results illustrated a decline in the expansion of conventional energy sources, with natural gas, wind energy and solar energy taking the place of thermal power generation. In terms of performance, solar power ranks second to wind. By assessing various expansion scenarios, it is demonstrated that zero nuclear energy growth would yield more competitive economic advantages and fewer GHG emissions than no geothermal expansion, whereas a 20% increase in gas expansion capacity would achieve the most optimal ratio at [304.2, 317.3] (Rand/t CO2 eq). By utilizing the proposed approach, decision-makers in developing countries can generate multiple expansion scenarios for Belt and Road Initiative (BRI) investments. This enables them to identify generation modes, capacity expansion schemes, financial planning, and carbon tax regulations, even under complex uncertainties.