Intermittent Electricity Generation Research Articles

Electric vehicle-based distant energy sharing between zero-emission coastal office and hotel buildings

With the rapid growth of distributed renewable energy systems, energy sharing brings a practical solution to mitigate mismatching between intermittent electricity generation and building demand. In past research, energy sharing was designed mostly for onshore energy integrated systems and is commonly realised with the assistance of microgrids, distributed battery storage, or peer-to-peer energy trading. This research innovatively proposed a distant energy sharing between the ocean energy-supported coastal office building and hotel building by ten electric vehicles, enabling the circulation of ocean renewable energy between two buildings. This project aims to accomplish maximum technical, environmental and economic benefits for the stakeholder. Using bidirectional vehicle-building interaction, advanced control algorithms, including shifting vehicle batches, sizing renewable capacity, and involving stationary batteries, are implemented successively in the TRNSYS simulation as analysis groups to enhance the current system's performance. According to the results, the vehicle-based bidirectional energy sharing between these two buildings can attain a relative net present value of 49.18 million HKD and a weighted matching index of 0.63. After implementing advanced controls with stationary batteries, the system achieved a relative net present value of 62.15 million HKD with an improved matching index of 0.70. Both batteries contributed to increase the matching performance of the system, but the increase in battery capacity reduces the benefit due to their replacement cost. This research developed an energy management system for effectively utilising electric vehicles and coastal renewable energy for distant energy sharing. It elucidated the technological, environmental, and economic benefits to the stakeholders for effective decision-making.

TransHyDE‐Sys: An Integrated Systemic Approach for Analyzing and Supporting the Transformation of Energy Systems and Hydrogen Infrastructure Development

In addition to the long‐term goal of mitigating climate change, the current geopolitical upheavals heighten the urgency to transform Europe's energy system. This involves expanding renewable energies while managing intermittent electricity generation. Hydrogen is a promising solution to balance generation and demand, simultaneously decarbonizing complex applications. To model the energy system's transformation, the project TransHyDE‐Sys, funded by the German Federal Ministry of Education and Research, takes an integrated approach beyond traditional energy system analysis, incorporating a diverse range of more detailed methods and tools. Herein, TransHyDE‐Sys is situated within the recent policy discussion. It addresses the requirements for energy system modeling to gain insights into transforming the European hydrogen and energy infrastructure. It identifies knowledge gaps in the existing literature on hydrogen infrastructure‐oriented energy system modeling and presents the research approach of TransHyDE‐Sys. TransHyDE‐Sys analyzes the development of hydrogen and energy infrastructures from “the system” and “the stakeholder” perspectives. The integrated modeling landscape captures temporal and spatial interactions among hydrogen, electricity, and natural gas infrastructure, providing comprehensive insights for systemic infrastructure planning. This allows a more accurate representation of the energy system's dynamics and aids in decision‐making for achieving sustainable and efficient hydrogen network development integration.

Evidence of households' demand flexibility in response to variable hourly electricity prices – Results from a comprehensive field experiment in Norway

Demand-side flexibility which reacts to hourly price signals is expected to play an essential role in balancing intermittent electricity generation in the future carbon-neutral power system. This study investigates the price responsiveness of households and various influencing factors through a pricing experiment which was implemented as a reward scheme and involved 3746 Norwegian households. These households, characterised by a highly electrified energy usage such as electric heating and charging electric cars, were subjected to variable hourly price signals with a one-day advance notification over the course of three winter months. The study reveals that households reduced their electricity demand by, on average, 2.92% in hours with high prices, and the reduction did not diminish significantly after repeated interventions. Moreover, an increased response could be observed for price signals with a short peak price period and when prices exceeded a threshold of 15 NOK/kWh. These results suggest that despite the limited potential of manual demand response from households, it can still be relied upon and utilised to enhance power system operations and planning. Additionally, to fully exploit its potential, it is recommended to enhance price responsiveness through tailored price information and by incentivising investments in automatic response and energy storage.

Comprehensive evaluation of the planned development of intermittent renewable sources within the EU

This paper deals with an assessment of the steps taken and planned by the EU (European Union) to achieve its climate neutrality by 2050. Emphasis is placed on the reality of achieving RES (renewable energy sources) in total energy production in individual countries according to the required values for 2030. A detailed analysis of the previously set goals of penetration of RES and their historical fulfillment was performed. Furthermore, an evaluation of the planned shutdown of traditional combustion sources and the overall loss of constant production power, which keeps the energy system stable with a sufficient amount of standby power in real time is performed. In connection with these facts of the EU plans of the shift away from coal power plants and the nature of the intermittent electricity generation of the used renewable sources within the EU and the historical dynamics of the RES production capacities installation are evaluated.

Angažovanje generatora i potrebe balansnih rezervi u prisustvu intermitentnih OIE: Studija slučaja elektroenergetskog sistema Srbije

Intermittent electricity generation of the various renewable energy sources sets additional burden on generation unit dispatching and reserve planning in day-ahead electricity market. The conventional unit commitment models which include rump-up and rump-down limits are usually presented with stepwise mathematical functions without clear distinction between power and energy. This paper presents a case study of generation unit dispatching planning approach for the case of pricewise-linear functions from one time interval to another, taking into account actual ramping trajectories thus providing more efficient reserve scheduling particularly during generators’ start-up and shut-down processes. For the representation of reserve schedules, the 10-min and 30-min ramp capabilities of the generation units are assumed where they are obliged to provide secondary, tertiary and offline-tertiary reserves depending on their technical capabilities. The Serbian power system case study represents a 24-hour unit commitment planning and up/down secondary and tertiary reserve requirements during a scarcity event when reserve flexibility of neighbouring power systems cannot be utilised. Formulation of the optimisation mathematical model is performed via GAMS, the General Algebraic Modelling System, and CPLEX optimiser is used for problem optimisation purposes.

Clean Energy Certificates and Emissions Seem to Be a Zero-Sum Game: Analyzing the Intermittent Electricity Generation in Mexico

Clean Energy Certificates and Emissions Seem to Be a Zero-Sum Game: Analyzing the Intermittent Electricity Generation in Mexico

A review of wind speed and wind power forecasting with deep neural networks

The use of wind power, a pollution-free and renewable form of energy, to generate electricity has attracted increasing attention. However, intermittent electricity generation resulting from the random nature of wind speed poses challenges to the safety and stability of electric power grids when wind power is integrated into grids on large scales. Therefore, accurate forecasting of wind speed and wind power (WS/WP) has gradually taken on a key role in reducing wind power fluctuations in system dispatch planning. With the development of artificial intelligence technologies, especially deep learning, increasing numbers of deep learning-based models are being considered for WS/WP forecasting due to their superior ability to deal with complex nonlinear problems. This paper comprehensively reviews the various deep learning technologies being used in WS/WP forecasting, including the stages of data processing, feature extraction, and relationship learning. The forecasting performance of some popular models is tested and compared using two real-world wind datasets. In this review, three challenges to accurate WS/WP forecasting under complex conditions are identified, namely, data uncertainties, incomplete features, and intricate nonlinear relationships. Moreover, future research directions are summarized as a guide to improve the accuracy of WS/WP forecasts.

Isothermal Versus Sensible Cold Storage: A Model-Based Performance Comparison for Pumped Thermal Electricity Storage

Abstract Pumped-thermal energy storage (PTES) systems consume and produce electrical energy using thermal storage media as an intermediate stage. PTES lends itself to long-duration energy storage to facilitate high penetration of intermittent electricity generation. This study presents a model-based comparison of two thermal storage types within a PTES system: a conventional, single-phase, stratified water-glycol sensible storage system (SGS), and an ideal isothermal, two-phase heat exchanger that freezes a water reservoir (isothermal heat exchanger (IHEX)). The SGS thermal storage capacity is based on the liquid’s sensible heat change with temperature, whereas the capacity of the IHEX is based on the latent heat of isothermally freezing and melting water. The idealized IHEX modeled here undergoes steady-state melting and freezing (in contrast to transient rates, as observed with ice-on-coil storage). A computational model of a complete PTES system is presented and used to evaluate the PTES system-level performance with each type of cold storage. Compared to SGS-based PTES, under nominal operating conditions, the IHEX-based PTES increased electrical round-trip efficiency from 61% to 82% and increased energy density from 1.13 to 8.09 kWh/m3 The performance of the PTES configured with IHEX storage was also analyzed under varying operating parameters.

Optimal Onsite Microgrid Design for Net-Zero Energy Operation in Manufacturing Industry

Developing an economic net-zero energy infrastructure for the manufacturing industry can play a critical role to achieve the goal of affordable, reliable, and sustainable clean energy paradigm for the next generation. However, it is quite challenging to develop such an infrastructure due to the uncertain demand of the manufacturing system, intermittent electricity generation from the renewable sources, time of use (TOU) pricing of electricity, and integrated operational planning for the long-term planning horizon. In this paper, a mixed-integer non-linear programming (MINLP) model is developed to economically design an onsite microgrid system considering the critical conditions and achieve a net-zero energy operation planning for the manufacturing industry. A linearization strategy is adopted to obtain the optimal design of the microgrid and the utilization of the resources. A numerical case study is conducted to evaluate the effectiveness of the model.

Geologic feasibility of underground hydrogen storage in Canada

Electricity production in the majority of Canada's regions is characterized by high proportions of nuclear and renewable sources such as hydroelectricity. Future plans to phase out coal-fired power plants by 2030 and decrease fossil fuel use in favor of increased integration of renewables highlight the need to develop strategies which can match intermittent and base-load electricity output with market demand. The use of hydrogen gas generated through off-peak electrolysis has been highlighted by the Canadian government as a potential avenue forward in managing electrical grids with surplus and intermittent electricity generation. This technology can be supported in a safe and cost-effective manner by underground hydrogen storage in geological formations. In this article, an overview of Canadian geology, as well as an assessment of the potential application of underground storage methods and associated safety concerns in Canada is presented. Favorable locations for pilot projects are found in the sedimentary basins of western and Atlantic Canada as well as southern Ontario, or the crystalline rocks of the Canadian Shield.

Bidirectional linkage between a long-term energy system and a short-term power market model

This paper proposes a novel bidirectional linkage between a long-term energy system model and an operational power market model. This combined modelling framework provides long-term energy system investment strategies that explicitly consider the operational complexity of the power sector. The linkage is demonstrated using an energy system model of Norway and a European power market model with a specific high detail level of hydropower operation. For Norway, with its hydropower-dominated electricity sector, the linkage is designed to improve the modelling of hydropower generation and external electricity markets in the energy system model, and to provide consistent assumptions concerning Norwegian electricity demand and capacity in the power market model. The difference in income of hydropower producers, which is endogenous in both models, is used as a convergence criterion. The linkage is tested for various future developments of the European power market and is successful for three of the four analysed instances. However, when the linkage is evaluated in a system with a very high share of intermittent electricity generation and large variations in electricity price, it fails to converge on hydropower income. This is because the simulated Norwegian electricity prices differ significantly between the two models in this situation.

Power to methanol technologies via CO2 recovery: CO2 hydrogenation and electrocatalytic routes

Abstract Various strategies are proposed to date in order to convert CO2 to large diversity of useful chemicals. The following review discusses two important approaches that produce methanol from CO2. These two includes CO2 hydrogenation and electrocatalytic routes. These processes could recycle CO2, permitting a carbon neutral, closed loop of fuel combustion and CO2 reduction to prevent a rising concentration of this greenhouse gas in the atmosphere. Besides, intermittent electricity generation can be stored in an energy-dense, portable form in chemical bonds. The present review reports more recent findings and drawbacks of these two processes. The present review study revealed that the hydrogenation process could become readily operational in comparison to electrocatalytic process. The electrocatalytic approach still has serious technical issues in terms of kinetically sluggish multi-electron transfer process during CO2 reduction reaction that requires excessive over-potential, relatively poor selectivity, poor durability in the long term, and the absence of the optimized standard experimental and commercial systems.

Internal hedging of intermittent renewable power generation and optimal portfolio selection

This paper introduces a scheme for hedging and managing production costs of a risky generation portfolio, initially assumed to be dispatchable, to which intermittent electricity generation from non-dispatchable renewable sources like wind is further added. The proposed hedging mechanism is based on fixing the total production level in advance, then compensating any unpredictable non-dispatchable production with a matching reduction of the dispatchable fossil fuel production. This means making no recourse to short term techniques like financial hedging or storage, in a way fully internal to the portfolio itself. Optimization is obtained in the frame of the stochastic LCOE theory, in which fuel costs and $$\hbox {CO}_2$$ prices are included as uncertainty sources besides intermittency, and in which long term production cost risk, proxied either by LCOE standard deviation and LCOE CVaR Deviation, is minimized. Closed form solutions for optimal hedging strategies under both risk measures are provided. Main economic consequences are discussed. For example, this scheme can be seen as a method for optimally including intermittent renewable sources in an otherwise dispatchable generation portfolio under a long term capacity expansion perspective. Moreover, within this hedging scheme, (1) production cost risk is reduced and optimized as a consequence of the substitution of the dispatchable fossil fuel generation with non-dispatchable $$\hbox {CO}_2$$ free generation, and (2) generation costs can be reduced if the intermittent generation can be partially predicted.

Convenience before coins: Household responses to dual dynamic price signals and energy feedback in Sweden

To enable and cope with an increase of intermittent electricity generation, the power industry and regulators are trying to incentivise users to use electricity at certain times through dynamic pricing and feedback. The effects of such interventions on patterns of electricity use have been extensively studied, yet little is known about how and why householders do or do not respond to such interventions. Using interviews and activity-based diaries, this study provides a qualitative exploration of how and why householders who are subject to a demand-based time-of-use distribution tariff, real-time retail pricing and real-time feedback, do or do not respond to such interventions in their daily lives. We find that the householders have adapted a range of existing practices and have started to engage in new ones that aim to reduce peak demand during peak hours, partly without the support of feedback. Drawing on theories of practice, we challenge common preconceptions about how and why price signals work by demonstrating how the size of the financial incentive that a price signal provides does not have that much influence on householders’ willingness to engage in demand response. We argue that price signals work by providing new meanings to practices that use electricity, that feedback can mediate these meanings, and that what matters for householders’ willingness to engage in demand response is that the changes they undertake do not cause them any inconvenience by limiting the temporal flexibility of other doings in their daily lives.

Integration of biocrude production from fast pyrolysis of biomass with solar PV for dispatchable electricity production

Abstract This article analyses the integration of distributed biocrude production facilities using fast pyrolysis with solar photovoltaic (PV) for dispatchable electricity production. The strong growth of intermittent electricity generation from solar PV and wind is leading to a greater need for energy storage at grid scale and dynamic demand management. Various forms of energy storage, including electrochemical (e.g. batteries), mechanical (e.g. flywheels) and gravitational (e.g. pumped-hydro), are being developed. This work studies the issues of integrating fast pyrolysis of biomass to produce biocrude that can be readily stored in tanks and combusted to produce electricity when required to supplement the electricity generation from a solar PV unit to meet an arbitrary energy demand curve. The use of biomass pyrolysis in this application has a range of benefits, including the flexibility to augment intermittent renewables, the integration of more bioenergy into the electricity sector and the creation of commercial quantities of biocrudes that can be refined into renewable transport fuels such as jet fuel for which few other alternatives exist. Biocrudes, especially partially upgraded, can be stored and used when required in engines and gas turbines, making them a suitable fuel for augmenting the intermittent nature of solar and wind projects. The development of the distributed 100% renewable power stations using a mix of biomass/biocrude and solar PV and/or wind would also increase the certainty of supply, knowledge of quality and price of raw biocrudes that can also be used to supply a centralized biorefinery, thereby substantially reducing the risk of investing in new biorefinery capacity.

Techno-economic comparison of the levelised cost of electricity generation from solar PV and battery storage with solar PV and combustion of bio-crude using fast pyrolysis of biomass

The strong growth of intermittent electricity generation from solar PV and wind is leading to a greater need for energy storage at grid scale. In this work a techno-economic model has been constructed to calculate the levelised cost of electricity for two systems that can meet an arbitrary energy demand curve: (1) solar PV and battery storage and (2) solar PV with combustion of bio-crude and bio-gas from biomass. The analysis is performed for conditions prevalent in Queensland, Australia where over a gigawatt of new solar PV capacity is being constructed in 2018. The battery storage assumes lithium-ion batteries and costs derived from the recently constructed Hornsdale Power Reserve in South Australia. A variable energy demand curve is assumed in the work. The model shows that the parameters with the most impact on the LCOE for the solar PV and battery system are the solar yield, and total installed costs of the battery and solar PV unit. Assuming, battery costs of 750 AUD/kWh, solar PV costs of 1.6 AUD/W and a project capacity of 240 MWh/d, the LCOE of the solar PV and battery system was calculated to be 170 AUD/MWh. Using total installed costs forecast for the near future, the LCOE is expected to be in the range 150–185 AUD/W for the variable energy demand curve, and over 200 AUD/MWh if a constant supply of power is required. The parameters with the most impact on the LCOE for the solar PV and bio-crude system are the solar yield and total installed cost of the biomass pyrolysis and bio-crude combustion unit. For a 240 MWh/d project scale with variable energy demand, the LCOE for the solar PV and bio-crude system is estimated to be 116 AUD/MWh. Variations in feedstock cost and project scale showed that the LCOE is in the range of 104–125 AUD/MWh. The main conclusion from this work, is that integration of solar PV and the production and combustion of bio-crude and bio-gas using fast pyrolysis of biomass, leads to competitively priced dispatchable renewable energy that is forecast to be cheaper than using solar PV and batteries for the foreseeable future. It has also been found that the combination of solar PV and bio-crude combustion leads to lower LCOEs than using bioenergy alone, due to the rapidly decreasing costs of large scale solar PV. While the solar PV and bio-crude system analysed in this work will likely be a niche solution, in areas with substantial biomass resources, it offers a credible starting point for the development of larger scale bioenergy value chains, with the longer term goal of converting lignocellulosic biomass materials into renewable transportation fuels and chemicals.

Demand Response Potential: Available when Needed?

The increase of intermittent electricity generation from renewable energy sources (RES) requires more flexibility from the demand side. Different applications and processes exist, which can provide Demand Response (DR) potential by shifting or shedding their load. The availability of most applications depend on the ambient temperature and/or time of day. Furthermore, their commitment is limited by technical restrictions, e.g. shifting time. In this paper, the availability and the flexibility of DR is analysed to investigate its role for the system integration of RES in Germany. In a first step, DR potential on an hourly basis is calculated for today and for future years. In a second step, the use of DR in an electricity system with different RES shares is investigated with an electricity market model. Results show, DR reduces RES curtailment. However, due to its limited availability and flexibility, it cannot integrate high amount of RES surplus over a longer period. Instead, it balances short-term fluctuation of the residual load curve. The exploited potential varies between DR applications because of their different characteristics. Therefore, focused (on selected applications) rather than broad development of DR potential is needed to shape the future energy system in a cost efficient way.

A two-part feed-in-tariff for intermittent electricity generation

As electricity generation from intermittent energy sources (wind, sun, tides) is gaining momentum, it becomes increasingly important to price these electricity sources efficiently. Conventional flat feed-in-tariffs ignore the heterogeneity of these sources. Taking into account the degree of substitutability or complementarity of these sources with respect to each other and with respect to stochastic demand variations, this paper derives optimal pricing instruments composed of a feed-in-tariff (FIT) and a capacity-augmentation-tariff (CAT). An empirical analysis looks at wind and solar farms operating in Ontario in order to determine the optimal use of FIT-CAT pricing. The magnitude of optimal price differentiation turns out to be economically significant. Furthermore, the emergence of grid-scale electricity storage underscores the need to price energy and capacity separately.

A systems approach to quantifying the value of power generation and energy storage technologies in future electricity networks

A new approach is required to determine a technology's value to the power systems of the 21st century. Conventional cost-based metrics are incapable of accounting for the indirect system costs associated with intermittent electricity generation, in addition to environmental and security constraints. In this work, we formalise a new concept for power generation and storage technology valuation which explicitly accounts for system conditions, integration challenges, and the level of technology penetration. The centrepiece of the system value (SV) concept is a whole electricity systems model on a national scale, which simultaneously determines the ideal power system design and unit-wise operational strategy. It brings typical Process Systems Engineering thinking into the analysis of power systems. The model formulation is a mixed-integer linear optimisation and can be understood as hybrid between a generation expansion and a unit commitment model. We present an analysis of the future UK electricity system and investigate the SV of carbon capture and storage equipped power plants (CCS), onshore wind power plants, and grid-level energy storage capacity. We show how the availability of different low-carbon technologies impact the optimal capacity mix and generation patterns. We find that the SV in the year 2035 of grid-level energy storage is an order of magnitude greater than that of CCS and wind power plants. However, CCS and wind capacity provide a more consistent value to the system as their level of deployment increases. Ultimately, the incremental system value of a power technology is a function of the prevalent system design and constraints.

Biogas Upgrading in a 50 Kilowatt Solid Oxide Cells Based Demonstration Plant - Design and Operational Experiences Including Strategies to Counteract Degradation

There are considerable incentives to use intermittent electricity generation for production of stporable energy carriers. Upgrading biogas to pipeline quality gas by methanation of the CO2 content in the biogas with hydrogen from electrolysis is one option. Solid Oxide electrolysis (SOEC) offer strong synergy with the methanation plant, as the steam produced by the exothermal methanation reaction can be used directly as feedstock for the SOEC thus eliminating water evaporation by electricity. A pilot plant to demonstrate the concept has been constructed and was operational mid 2016. The design capacity is 10 Nm3/h of upgraded biogas. This capacity requires approx. 50 kW SOEC, which is provided by two Fuel Cores, each consisting of 4 SOEC stacks. Haldor Topsøe A/S has also designed the biogas cleaning unit and the methantion plant which is located at the Agricultural Research Centre of Aarhus University at Foulum, Jutland. The paper will outline the design of the pilot as well as full scale plants including exergy analyses. Experimental data from the SOEC unit(s) as well as the biogas cleanup and methanation pilot will be presented. Figure 1