Low Capacity Factors Research Articles

Calix[4]arene-decorated polymers of intrinsic microporosity for lithium isotopes separation

Due to the importance of lithium isotopes in the nuclear energy industry, there are increasing number of researchs on the lithium isotopes separation in recent years. However, the adsorbents used for lithium isotopes separation suffer from the low adsorption capacity and isotopes separation factor in aqueous phase, and is difficult to meet the requirements for industrial lithium isotopes production. In this work, two types of calix[4]arenes with different rim groups were incorporated into the polymer backbone. Both calix[4]arene decorated PIMs exhibited good lithium adsorption capacities in aqueous phase. Among them, 4-tert-butyl-calix[4]arene decorated PIM showed excellent lithium isotopes separation performance with a maximum lithium adsorption capacity of 67.99 mg·g−1 and an isotopes separation factor of 1.034 ± 0.003 in aqueous phase. The ease of preparing and stable cycling performance makes it potentially useful for industrial lithium isotopes production.

Novel Recuperated Power Cycles for Cost-Effective Integration of Variable Renewable Energy

The ongoing transition to energy systems with high shares of variable renewables motivates the development of novel thermal power cycles that operate economically at low capacity factors to accommodate wind and solar intermittency. This study presents two recuperated power cycles with low capital costs for this market segment: (1) the near-isothermal hydrogen turbine (NIHT) concept, capable of achieving combined cycle efficiencies without a bottoming cycle through fuel combustion in the expansion path, and (2) the intercooled recuperated water-injected (IRWI) power cycle that employs conventional combustion technology at an efficiency cost of only 4% points. The economic assessment carried out in this work reveals that the proposed cycles increasingly outperform combined cycle benchmarks with and without CO2 capture as the plant capacity factor reduces below 50%. When the cost of fuel storage and delivery by pipelines is included in the evaluation, however, plants fired by hydrogen lose competitiveness relative to natural gas-fired plants due to the high fuel delivery costs caused by the low volumetric energy density of hydrogen. This important but uncertain cost component could erode the business case for future hydrogen-fired power plants, in which case the IRWI concept powered by natural gas emerges as a promising solution.

Decarbonizing of power plants by ammonia co-firing: design, techno-economic, and life-cycle analyses

ABSTRACT This research investigates the decarbonization of India’s electricity grid using ammonia in power plants. It focuses on ammonia produced in Western Australia and transported to India, co-fired with high rank coal, and compared with power plants utilizing carbon capture and sequestration (CCS). The study assesses the overall costs and the life cycle greenhouse gas (LC GHG) emissions for both new plants and retrofits. For 20% gray, blue, and green ammonia, the levelized cost of electricity is 86, 89, 125 $/MWh, with corresponding LC GHG emissions of 1,234, 1,079, and 1,062 kg CO2e/MWh. Co-firing with green ammonia, though more expensive than blue ammonia, yields lower CO2 emissions. Conversely, reducing the same amount of direct CO2 emission via CCS costs $84/MWh and a LC GHG emission of 1,227 kg CO2e/MWh. While CCS is cheaper, it results in higher LC GHG. There is a trade-off between cost and emissions across the strategies. Under scenarios with low capacity factors or reduced ammonia production costs, coal-ammonia co-firing could become more economical and greener than the CCS. This study provides quantitative insights for policymakers and project developers. However, it is crucial for decision-makers to consider several factors: (1) the potential impact of social resistance to CCS; (2) the time required for large-scale commercialization of CCS technology, which is expected to be significantly longer than the implementation time for a coal-ammonia co-firing decarbonization strategy; (3) the potential of either CCS or ammonia-coal co-firing strategy to enhance India’s electricity mix, thus contributing to energy security.

An exergoeconomic exploration of solar-geothermal integration

This study investigates the integration of a solar field using parabolic trough collectors into a binary geothermal plant with isopentane as the secondary fluid, employing the Engineering Equation Solver (EES) and System Advisor Model (SAM) for analysis. The investigation evaluates the performance of two Heat Transfer Fluids (HTFs)—Therminol VP-1 and molten salts—in hybrid configurations, emphasizing variations in solar field size and thermal storage capabilities. First, a direct correlation has been identified between second law efficiency and Levelized Cost of Energy (LCOE), demonstrating that increases in thermal storage from 0 to 12 h result in LCOE increments up to 33%. The study highlights that molten salts, achieving the lowest LCOE of 0.075 USD/kWh, enhance net energy output by up to 15.55% compared to Therminol VP-1, particularly under extended storage conditions. Additionally, the integration of larger solar fields and increased storage capacities significantly impacts the costs of high-pressure steam production, which rise from 33.02 to 50.55%. By expanding plant capacity factors up to 97% for Therminol and 93% for molten salts with optimal thermal storage and solar multiple configurations, the study demonstrates that molten salts enable greater annual power output despite lower capacity factors. This comprehensive analysis underscores the pivotal role of second law analysis in optimizing the economic and operational efficiencies of hybrid geothermal-solar power systems, offering significant insights for enhancing the design and economic viability of renewable energy integrations.

FMEA-Based Logistic Regression Model for the Evaluation of Photovoltaic Power Plant Risk

The purpose of this research is to identify the primary operational risks associated with photovoltaic power plants and develop effective risk management strategies to optimize the operation of existing plants and mitigate risks for future plants that will be constructed as part of the new renewable energy (EBT) transition agenda until 2030. The integration of Failure Mode and Effect Method Analysis (FMEA) with logistic regression provides the formation of a risk treatment ranking that management should prioritize. Risk assessment relies on the expertise and experience of professionals in performing their responsibilities associated with photovoltaic power plants. The research findings have identified 10 potential risks associated with improving photovoltaic power plants operations to prevent failure or damage to the system. These risks are categorized into five stages of the operation process: planning and procurement, installation, operation, and maintenance. Risk rankings and mitigation are generated to prioritize actions aimed at limiting the occurrence of failure/damage and low-capacity factors in photovoltaic power plants as recommendations for the management.

Solar-hydro cable pooling – Utilizing the untapped potential of existing grid infrastructure

Over the years, the coupling of various variable renewable energy sources has emerged as a convenient way to partially or fully overcome their highly intermittent nature and low-capacity factors. In literature as well as in practical implementations, the coupling of solar and wind power systems is gaining special attention thanks to their advantageous complementarity in time. However, an area of yet not well-documented potential is the coupling of solar PV plants with non-dispatchable run-of-river hydropower plants. In this study, Poland, which still has significant untapped hydropower potential, is used as a case study. The objective of the work is to quantify the coupling potential with special attention paid to the unavoidable curtailment of solar generation due to the limited grid connection capacity. A simulation model was developed that uses input runoff, irradiation, and temperature hourly data covering the period 01.01.2008–31.12.2022 for 236 selected sites in Poland. Hydrological data were obtained from field measurements, while the remaining meteorological parameters were downloaded from the ERA5 reanalysis database. Hydropower generation was simulated assuming a constant head and a Kaplan turbine operating at different efficiencies depending on the flow rate through the turbine. The available flow was calculated considering environmental flow (e-flows) constraints. The design flow was determined based on the average multi-year flow in the considered river. The complementarity in time of these two renewable energy sources in each location was assessed by considering the grid connection capacity and resulting curtailment in case of too high simultaneous generation from both sources. The analysis showed that the average PV curtailment is about 10.7 % (or 13.2 % when it is solar PV capacity weighted) when the ratio of solar to hydro is equal. Still, it can be as high as 19.7 % in individual cases. To ensure that PV curtailment is no more than arbitrarily (in that case) selected threshold of 5 %, the solar-PV capacity should be between 58 % − 120 % of the designed hydropower plant capacity. The curtailment threshold can be further investigated as an expansion of a techno-economic analysis that fell out of the scope of this work. The additional analysis conducted by means of daily flow data showed a significant underestimation of solar curtailment in individual cases (i.e., up to 7 pp.) and, on average, lower by 0.24 pp. could be expected. Due to interannual flow variations, although the expected mean solar curtailment can be no more than 5 %, there are individual years when it is as low as 2 % and as high as 12 % of this year’s solar generation. The lessons learned from this study shed light on the potential maximization of local power generation through coupling with PV systems and the simultaneous reduction of environmental impacts by releasing higher quantities of e-flows offset by the integration of PV systems.

Scaling of wave energy converters for optimum performance in the Adriatic Sea

The wave energy potential in the Adriatic Sea is investigated at seven offshore locations, and the mean annual energy, average electric power production, operating hours, as well as the coefficient of variation of the monthly power production are determined for three wave energy converters. Since wave energy converters are commonly designed and optimized to extract energy from ocean waves, they have low capacity factors in low-energy seas or bays such as the Adriatic Sea, where the sea states are slight to moderate. The scaling of the wave energy converters is performed on the basis of the Froude scaling law for AquaBuoy and Pelamis devices. The results of WECs at eleven scales are compared with those obtained for a Lysekil WEC. The obtained results show that the capacity factors of the downscaled WECs increase significantly at their optimum scales, reaching about 29 % and 42 % for the AquaBuoy and Pelamis, respectively, depending on the location. By comparing the results obtained for the AquaBuoy and Pelamis at a scale of 0.7 with the results of a full-scale Lysekil WEC, it may be concluded that the downscaled WECs may be more suitable for the considered locations in the Adriatic Sea while keeping their economic viability.

Limited impact of hydrogen co-firing on prolonging fossil-based power generation under low emissions scenarios

Climate change mitigation generally require rapid decarbonization in the power sector, including phase-out of fossil fuel-fired generators. Given recent technological developments, co-firing of hydrogen or ammonia, could help decarbonize fossil-based generators, but little is known about how its effects would play out globally. Here, we explore this topic using an energy system model. The results indicate that hydrogen co-firing occurs solely in stringent mitigation like 1.5 °C scenarios, where around half of existing coal and gas power capacity can be retrofitted for hydrogen co-firing, reducing stranded capacity, mainly in the Organization for Economic Co-operation and Development (OECD) countries and Asia. However, electricity supply from co-firing generators is limited to about 1% of total electricity generation, because hydrogen co-firing is mainly used as a backup option to balance the variable renewable energies. The incremental fuel cost of hydrogen results in lower capacity factor of hydrogen co-fired generators, whereas low-carbon hydrogen contributes to reducing emission cost associated with carbon pricing. While hydrogen co-firing may play a role in balancing intermittency of variable renewable energies, it will not seriously delay the phase-out of fossil-based generators.

The role of repowering India’s ageing wind farms in achieving net-zero ambitions

India’s ambitious net-zero climate goals include plans for a four-fold increase in current levels of wind energy generation by 2030. Many existing wind farms in India occupy sites with the best wind resources nationally but use older, smaller turbines that achieve lower capacity factors compared to modern turbine designs. A strategy of replacing existing wind turbines with state-of-the-art models (termed repowering) could boost capacity factors and ensure maximal use of available wind resources. However, a nationwide assessment of the potential wind generation increases resulting from repowering is currently lacking for India. Here, we present the first validated synthetic wind generation dataset for India based on reanalysis data and show that full repowering of the existing fleet of wind turbines could boost capacity factors by 82% nationwide (from 0.19 to 0.35). Our assessment of attainable capacity factors under full repowering exceeds equivalent estimates within the National Electricity Plan of India and national decarbonisation pathways compiled by the Intergovernmental Panel on Climate Change (IPCC), suggesting less total installed capacity is required to achieve specific generation outcomes than previously estimated. Ongoing technological progress, leading to increased turbine dimensions, will drive capacity factors beyond the levels estimated here, which could further add to the generation benefits of repowering. Yet, despite the higher average output from a repowered fleet of wind generators, substantial variability in generation across timescales persists, highlighting the increasing need for power system flexibility within a decarbonised energy system.

Techno-Economic Analysis of Reverse Osmosis Desalination Plant Powered by Hybridized PV and CSP Systems for Irrigation Water

Large market opportunities exist for solar powered Reverse Osmosis (RO) desalination technologies in fertile but arid areas with large solar and sea water resources. A challenge to realizing these markets is the variable nature of solar resources, which for the desalination plant can lead to high water costs due to low capacity factors (CF) and increased maintenance costs due to repeated start-ups and shut-downs. A potential solution is to power RO plants using both PV and CSP with Thermal Energy Storage (TES) with an aim to reduce shut-downs, and increase CF. In this study, three solar energy systems to power RO are considered: 1) PV only; 2) CSP with central receiver (CR) and TES; 3) PV and CSP with CR and TES. Two RO operational strategies are considered: 1) nominal load only; 2) variable load between minimal and nominal. The performance of these systems is simulated for Mersin, Turkey, using TMY data. The PV and CSP with TES system and variable RO operation achieved the levelized cost of water (LCOW) 1.92 USD m-3 with an RO CF of 60.8%.

Electrolysis as a flexibility resource on energy islands: The case of the North Sea

Energy islands are meant to facilitate offshore sector integration by combining offshore wind energy with power-to-x technologies and storage. In this study, we investigate the operation of electrolysers on energy islands, assess their potential contribution to flexibility provision, and analyse different market integration strategies of the islands. For this purpose, a two-stage stochastic optimisation model is developed to determine the cost-efficient dispatch for an integrated day-ahead and balancing electricity market. For the market integration of the energy island, we align our approach to the current debate and compare the case of a single offshore bidding zone to a case where the energy island is integrated into a home market zone. We find that electrolysers on energy islands will run at low capacity factors and provide flexibility in 29–36% of their run time. In addition, offshore electrolysers produce more hydrogen when they are allocated to an offshore bidding zone, and thus earn higher profits. We conclude that combining offshore wind with electrolysers on an energy island relies on additional economic incentives if their main role is envisioned to be the delivery of balancing flexibility.

Offshore wind power around the Iberian Peninsula: variability, complementarity and added value for the power system

The advances in floating offshore wind energy are opening deep sea areas, like the coastal waters of Iberian Peninsula (IP), for the installation of wind farms. The integration of this new energy source in a semi-closed power system with an already high share of variable renewable energies would be facilitated if the potential contribution of offshore wind energy shows reduced variability and limited seasonal variations, as the power demand in IP shows two maxima in winter and summer. The aims of this study are the analysis of temporal variability and spatial complementarity of the potential installation sites, and the identification of an optimal combination of installation areas that minimizes the temporal variability of the aggregated offshore contribution. In order to better capture the marked mesoscale features of winds around the IP, wind data from a very high resolution reanalysis (COSMO-REA6) are used. The analysis considers allowed areas for installation, delimited by the maritime spatial planning. Northern coast areas are characterized by high capacity factors (CFs) and high seasonality, while the lower CFs at the western and southern coasts are compensated by a limited seasonality. Pairwise correlation between the potential areas shows outstanding results, with several negative correlation values within a synoptic scale region, in contrast to other mid-latitude regions like the North Sea or the Eastern USA coast. An optimal aggregation of areas includes at least one area at each of the four main Iberian coasts. A strong reduction of hourly variability is obtained through the resulting combinations, and the seasonality of the aggregated CF is clearly below the values for other offshore areas. Therefore, offshore wind energy can indeed offer an added value for the Iberian power system beyond the high resource amount, reducing the need for storage or backup plants.

Heat pump-driven adsorption CO2 capture for simple and cost-effective retrofits of coal power plants

Coal-fired power plants emit almost a third of fossil CO2 emissions worldwide, and continued operation of existing plants will consume the entire remaining CO2 budget for 1.5 °C of global warming. Hence, there is an urgent need to rapidly cut emissions from existing power plants. The continuous swing adsorption reactor (CSAR) concept offers a promising solution to this challenge. CSAR uses electrically powered heat and vacuum pumps to drive the CO2 capture process and does not require the extraction of large amounts of steam from the power plant, greatly simplifying the retrofit process. A bottom-up techno-economic assessment of CSAR compared to conventional temperature swing adsorption (TSA) using the same sorbent showed near-identical performance in terms of energy penalty (8.0 for CSAR and 8.2 %-points for TSA) and CO2 avoidance cost (54.1 €/ton for CSAR and 55.4 €/ton for TSA). Hence, retrofitting simplicity is achieved at no extra cost. The assessment also showed that, although new coal-fired power plants are economically unviable in regions with already high CO2 prices, already depreciated plants will be difficult to displace via market forces. For example, the levelized cost of electricity for a coal power plant retrofitted with CSAR drops from 99.2 €/MWh to 68.2 €/MWh when the power plant is already depreciated. When CO2 prices rise, the optimal strategy involves retrofitting plants located close to CO2 storage or utilization opportunities for continued baseload operation, while unabated plants without easy access to storage are used at lower capacity factors to integrate rising shares of variable renewables. Simplified retrofitting via CSAR can facilitate the practical and economical execution of this strategy, achieving rapid decarbonization while minimizing the need for new capital investments and disruptive early asset retirements.

Techno-Economic Analysis of Reversible and Paired Solid Oxide Cell Systems for Hydrogen Production

The United States (U.S.) Department of Energy (DOE) National Energy Technology Laboratory (NETL) has been pursuing the development of solid oxide cell (SOC) technology to enable future power generation systems with high efficiencies and low emissions. Government and industry net-zero goals are driving interest in approaches to decarbonize challenging sectors of the economy, such as industrial applications. Hydrogen (H2) – including that produced by SOC technology-based high-temperature electrolysis – is one promising route. At present, low prices for low-greenhouse gas intensity electrical power (i.e., renewable sources such as wind and solar) are available intermittently (at low-capacity factors), complicating the economics of clean hydrogen produced by electrolysis. Reversible solid-oxide cell (r-SOC) based power to gas systems have the potential to address this challenge by producing power when electricity prices are high and hydrogen when they are low. Plants with the ability to co-generate power from solid oxide fuel cells (SOFC) and hydrogen from solid oxide electrolysis cells (SOEC) are of particular interest for their dual revenue streams and the flexibility they can provide to the grid.This study investigates the cost and performance of two configurations of co-generating SOC plants. The first includes an r-SOC stack that alternates between power and hydrogen production. The second plant contains paired SOFC and SOEC stacks that are each dedicated to generating a single product when operated. For the purposes of this study, the plants are primarily intended to generate hydrogen, only switching to power production mode when market conditions are favorable. The study aims to elucidate expected tradeoffs between the higher capital cost of the paired SOFC/SOEC plant and the higher degradation rate of the r-SOC.The anticipated tradeoff of a reversible system is an increased degradation rate for lower capital costs. This is due to the paired systems being optimized for either fuel cell or electrolysis operation while the reversible system is not optimized for either. To quantify the impact of this, a base case where the SOFC, SOEC, and r-SOC all degrade performance-wise at the same rate (0.2% per 1000 h). The degradation rate of the r-SOC is then allowed to float to where the levelized cost of hydrogen (LCOH) of the two systems is at parity, which does not occur at the base case assumptions. Additional sensitivity analyses are performed on natural gas price and cost of imported power to determine which system is more favorable under different assumptions.In summary, the results show that the total plant cost of the paired SOFC/SOEC system is about 5% higher than the reversible system. The additional cost of having two separate SOC modules is largely diluted by the balance of plant costs. The LCOH of the r-SOC and paired SOFC/SOEC are ≈$3.60/kg and ≈$3.30/kg H2, respectively as shown in Figure 1. Despite the higher capital cost, the paired SOFC/SOEC has a more favorable LCOH. This is due to the SOFC’s ability to generate electricity cheaper than the assumed $60/MWh grid purchase price. Sensitivity analyses show how the assumed cost of grid power and natural gas price affects the disposition of hydrogen versus electron generation. As an example, the LCOH of the r-SOC becomes more favorable than the paired SOFC/SOEC at natural gas prices above $12/MMBtu and at electricity purchase prices below $27/MWh.In conclusion, this investigation shows that depending on the market situation and final application, reversible SOC units warrant consideration for inclusion in advanced integrated energy systems as grid electricity prices continue to decrease over time.For the purposes of this study, natural gas is used as the fuel for power generation operation, and the systems are equipped with high rate (≈98%) carbon capture. In future work, stored hydrogen may be examined as the fuel for power generation. Future analyses may also examine the use of industrial or other waste heat sources, as well as perform life cycle analyses for the cradle-to-gate greenhouse gas intensity for select system configurations and applications. Figure 1

Techno-economic optimization of molten salt based CSP plants through integration of supercritical CO2 cycles and hybridization with PV and electric heaters

The present study explores the integration of supercritical CO2 (sCO2) power cycles into Concentrating Solar Power (CSP) plants using molten salt, and the hybridization of these plants with solar photovoltaic (PV) systems through electric heaters. Techno-economic evaluations determined the optimal power cycle configuration and subsystem designs for two different scales and locations and then compared them with state-of-the-art solar power plants. The results show that hybridizing PV with state-of-the-art CSP can lead up to a 22% reduction in the Levelized Cost of Electricity (LCOE) compared to standalone CSP systems. This hybridization and the use of electric heaters are particularly beneficial for small-scale installations and locations with low DNI/GHI ratios. By replacing the steam Rankine cycle with a sCO2 power block, a further 42% reduction in LCOE can be achieved at small scales, even with a simple recuperated cycle. In conclusion, the hybridization with PV and the integration of sCO2 power blocks provide cost benefits despite the temperature limitations imposed by the molten salt. Hybrid PV-CSP plants with sCO2 power blocks prove to be a cost-effective solution for capacity factors exceeding 60%. For lower capacity factors, configurations combining PV with battery energy storage or PV with electric heaters, thermal energy storage, and sCO2 power blocks are preferable options.

Technoeconomic Analysis for Green Hydrogen in Terms of Production, Compression, Transportation and Storage Considering the Australian Perspective

This current article discusses the technoeconomics (TE) of hydrogen generation, transportation, compression and storage in the Australian context. The TE analysis is important and a prerequisite for investment decisions. This study selected the Australian context due to its huge potential in green hydrogen, but the modelling is applicable to other parts of the world, adjusting the price of electricity and other utilities. The hydrogen generation using the most mature alkaline electrolysis (AEL) technique was selected in the current study. The results show that increasing temperature from 50 to 90 °C and decreasing pressure from 13 to 5 bar help improve electrolyser performance, though pressure has a minor effect. The selected range for performance parameters was based on the fundamental behaviour of water electrolysers supported with literature. The levelised cost of hydrogen (LCH2) was calculated for generation, compression, transportation and storage. However, the majority of the LCH2 was for generation, which was calculated based on CAPEX, OPEX, capital recovery factor, hydrogen production rate and capacity factor. The LCH2 in 2023 was calculated to be 9.6 USD/kgH2 using a base-case solar electricity price of 65–38 USD/MWh. This LCH2 is expected to decrease to 6.5 and 3.4 USD/kgH2 by 2030 and 2040, respectively. The current LCH2 using wind energy was calculated to be 1.9 USD/kgH2 lower than that of solar-based electricity. The LCH2 using standalone wind electricity was calculated to be USD 5.3 and USD 2.9 in 2030 and 2040, respectively. The LCH2 predicted using a solar and wind mix (SWM) was estimated to be USD 3.2 compared to USD 9.6 and USD 7.7 using standalone solar and wind. The LCH2 under the best case was predicted to be USD 3.9 and USD 2.1 compared to USD 6.5 and USD 3.4 under base-case solar PV in 2030 and 2040, respectively. The best case SWM offers 33% lower LCH2 in 2023, which leads to 37%, 39% and 42% lower LCH2 in 2030, 2040 and 2050, respectively. The current results are overpredicted, especially compared with CSIRO, Australia, due to the higher assumption of the renewable electricity price. Currently, over two-thirds of the cost for the LCH2 is due to the price of electricity (i.e., wind and solar). Modelling suggests an overall reduction in the capital cost of AEL plants by about 50% in the 2030s. Due to the lower capacity factor (effective energy generation over maximum output) of renewable energy, especially for solar plants, a combined wind- and solar-based electrolysis plant was recommended, which can increase the capacity factor by at least 33%. Results also suggest that besides generation, at least an additional 1.5 USD/kgH2 for compression, transportation and storage is required.

Cost of small-scale dispatchable CO2 capture: Techno-economic comparison and case study evaluation

Dispatchable power sources are crucial for electricity system stability and security of supply. Currently, the United Kingdom uses small-scale (<50 MWe) gas turbines to provide this function. To ensure we reach Net-Zero emissions by 2050, these small-scale dispatchable generators will require CO2 abatement; however, limited studies focus on these forms of power generation.In this work, we use process models developed in our previous studies, to calculate the levelised cost of electricity (LCOE) for a small-scale gas turbine equipped with Carbon Capture and Storage (CCS). The results show that the inclusion of CCS for these dispatchable generators increases the LCOE from 172 £/MWh to 514 £/MWh, almost tripling the cost of electricity. This is due to economies of scale and the low capacity factor. As these generators operate for less than 20% of the year, the levelised cost is drastically higher than other forms of low-carbon power. Dispatchable power is usually more expensive due to the small plant size and transient operation, and including CCS exacerbates this issue. Future work should focus on alternative forms of CO2 capture (designed specifically for small-scale gas turbines) and different dispatchable power generation, i.e., hydrogen and energy storage.

Optimization of a Tidal–Wind–Solar System to Enhance Supply–Demand Balancing and Security: A Case Study of the Goto Islands, Japan

Due to the expected increase in electric power demand in the coming decades and the economic and environmental issues caused by power generation from the combustion of hydrocarbon fuels, the integration of renewable energy into the grids of remote islands has attracted attention. Among all renewable sources, tidal stream energy shows potential to contribute positively in areas with strong tidal currents due to the predictability and semi-diurnal periodicity of the resource, which makes it compatible with short-term energy storage. However, its performance in areas with lower available power density has not yet been addressed. In this paper, energy systems for the Goto Islands, Japan which combine solar, offshore wind, and tidal energy are evaluated based on whole-system performance indicators such as the annual energy shortage and surplus and the battery load factor. Without energy storage, an energy mix of 31% solar, 47% offshore wind, and 22% tidal energy provides the lowest values for annual energy shortage (29.26% of total power demand) and surplus (29.26%). When batteries are incorporated into the system, tidal stream energy is the main contributor to reducing these two parameters, with values up to 23.58% and 19.60%, respectively, for the solar and tidal scenario with 30 MW of installed storage capacity. These results show the advantages of tidal stream energy exploitation in stand-alone energy systems, even with relatively low capacity factors (0.33).

Techno-Economic Analysis of Reversible and Paired Solid Oxide Cell Systems for Hydrogen Production

The use of green hydrogen to decarbonize the U.S. economy has been steadily gaining commercial interest as the cost and availability of renewable electricity decreases. At present, technologies can only take advantage of low electricity prices at low capacity factor, due to its intermittent availability, negatively impacting the economics. Reversible solid-oxide cell (r-SOC) based energy conversion systems can potentially solve this problem by producing power when electricity prices are high and hydrogen when they are low. However, the long-term operation of r-SOC systems has not been fully investigated compared to paired SOFC and SOEC units. This paper presents techno-economic results for two SOC-based hydrogen and power co-generation concepts. These technologies primarily generate hydrogen through solid oxide electrolysis but have the capacity to switch to power if signaled by the market. This operational flexibility provides a significant benefit to an electric grid with a growing share of variable renewable energy generation.

Climate change mitigation with carbon capture: An overview

The world is at the verge of catastrophe occasioned by the effect of climate change. Drastic action needs to be taken to reverse this ugly trend. Some of the proffered solutions to global warming is the adoption of renewable energy usage and a stop of fossil fuels combustion. However, the low capacity factor and energy return has been the bane on the usage of some renewable energy sources. A leeway however, exists in the technology of removal of greenhouse gases referred to as Carbon Capture. The widely adopted method being at point source because of its high concentration favouring easier processes of removal. This technology has received increased attention over the years as evident from data for the past five years. However, this technology alone cannot guarantee atmospheric CO2 levels required to maintain global temperature rise below the 1.50C mark. Negative emission technology processes of which the Direct Air Capture (DAC) is one needs to be developed. The infancy of the DAC technology and the uncertainties that surrounds its cost still pose as challenges. The cost of removing a tonne of CO2 with DAC technology can be as high as $600, this is unsustainable and has to be drastically reduced. While it is projected that DAC technology can take out 980 Metric Tonne (MT) CO2/annum by 2050, current figures stand at 0.008 MT. It is our view that the development of solid adsorbents and the harnessing of the thermal energy inherent in the sun can be a game changer.