Power systems for South and Central America based on 100% renewable energy (RE) in the year 2030 were calculated for the first time using an hourly resolved energy model. The region was subdivided ...into 15 sub-regions. Four different scenarios were considered: three according to different high voltage direct current (HVDC) transmission grid development levels (region, country, area-wide) and one integrated scenario that considers water desalination and industrial gas demand supplied by synthetic natural gas via power-to-gas (PtG). RE is not only able to cover 1813 TWh of estimated electricity demand of the area in 2030 but also able to generate the electricity needed to fulfil 3.9 billion m3 of water desalination and 640 TWhLHV of synthetic natural gas demand. Existing hydro dams can be used as virtual batteries for solar and wind electricity storage, diminishing the role of storage technologies. The results for total levelized cost of electricity (LCOE) are decreased from 62 €/MWh for a highly decentralized to 56 €/MWh for a highly centralized grid scenario (currency value of the year 2015). For the integrated scenario, the levelized cost of gas (LCOG) and the levelized cost of water (LCOW) are 95 €/MWhLHV and 0.91 €/m3, respectively. A reduction of 8% in total cost and 5% in electricity generation was achieved when integrating desalination and power-to-gas into the system.
Research on climate change impacts on renewable energy is becoming increasingly relevant due to the vulnerability of the sector and to the continual development of methodologies and availability of ...data. Public and private decision-making needs specific research. However, many gaps still exist in certain geographical regions and technologies. Providing economic estimates with a value chain perspective are also missing from most papers. This paper addresses the most relevant studies that project quantitative estimates of climate change impacts on solar, wind, hydro and other renewable generation technologies. Summary tables of impacts and projections are provided so that researchers, governments and the private sector may have an accurate view of the state-of-the-art on this topic.
•The impacts of climate change on renewables make up a growing area of research.•Despite uncertainties, climate models are the most well-trusted method.•Comparing projections is complex due to scopes, methodologies and variables.•Hydro and solar are more frequently analysed than other technologies.•Main gaps are lack of economics assessments and projections in developing countries.
•Green ammonia can be produced for 370–450 €/tonne in all continents by 2030.•The production costs at the best sites could decline to 285–350 €/tNH3 by 2050.•Coal-based ammonia in China is the first ...to be substituted by green ammonia.•Flexible synthesis units have a major role in low-cost green ammonia production.•PV is a dominating source of power supply to islanded plants in most of the world.
Ammonia is one of the most commonly used feedstock chemicals globally. Therefore, decarbonisation of ammonia production is of high relevance towards achieving a carbon neutral energy system. This study investigates the global potential of green ammonia production from semi-flexible ammonia plants utilising a cost-optimised configuration of hybrid PV-wind power plants, as well as conversion and balancing technologies. The global weather data used is on an hourly time scale and 0.45° × 0.45° spatial resolution. The results show that, by 2030, solar PV would be the dominating electricity generation technology in most parts of the world, and the role of batteries would be limited, while no significant role is found for hydrogen-fuelled gas turbines. Green ammonia could be generated at the best sites in the world for a cost range of 440–630, 345–420, 300–330 and 260–290 €/tNH3 in 2020, 2030, 2040 and 2050, respectively, for a weighted average capital cost of 7%. Comparing this to the decade-average fossil-based ammonia cost of 300–350 €/t, green ammonia could become cost-competitive in niche markets by 2030, and substitute fossil-based ammonia globally at current cost levels. A possible cost decline of natural gas and consequently fossil-based ammonia could be fully neutralised by greenhouse gas emissions cost of about 75 €/tCO2 by 2040. By 2040, green ammonia in China would be lower in cost than ammonia from new coal-based plants, even at the lowest coal prices and no greenhouse gas emissions cost. The difference in green ammonia production at the least-cost sites in the world’s nine major regions is less than 50 €/tNH3 by 2040. Thus, ammonia shipping cost could limit intercontinental trading and favour local or regional production beyond 2040.
•We investigate the techno-economic feasibility of geothermal-based carbon dioxide removal schemes for high temperature hydrothermal systems.•We calculated the thermodynamic, sequestration and ...financial outputs of geothermal-CDR configurations.•We demonstrated that geothermal-CDR configurations can be more cost-effective than conventional geothermal plants.•Net atmospheric carbon dioxide removal of 1 1 MtCO2/year can require up to $2.2–2.3 billion in total investment costs via these configurations.•These configurations can increase worldwide access to low-enthalpy geothermal resources and offset hard-to-abate residual emissions.
Limiting global temperature rise to between 1.5 and 2 °C will likely require widespread deployment of carbon dioxide removal (CDR) to offset sectors with hard-to-abate emissions. As financial resources for decarbonization are finite, strategic deployment of CDR technologies is essential for maximizing atmospheric CO2 reductions. Carbon capture and sequestration (CCS), using either direct air capture (DACCS) or bioenergy (BECCS) technologies has a particular synergy with geothermal electricity generation. This is because expensive geothermal infrastructure can be leveraged to transport dissolved CO2 for storage in subsurface reservoirs.
Here, we present a techno-economic comparison of renewable electricity generation coupled with either BECCS or DACCS at high-temperature, low-gas hydrothermal systems. We use a systems model that quantifies energy, carbon and financial flows through a generic hybrid power plant. At a CO2 market price of $100/tonne, the geothermal-BECCS system has a lower median cost of electricity generation ($88/MWh) than geothermal-DACCS ($181/MWh) and conventional geothermal ($89/MWh).
Geothermal-BECCS also had the lowest costs of overall emissions abatement, $122/tCO2, accounting for carbon removal and assuming displacement of fossil-fuel generation. Abatement costs are even lower, $45/tCO2, for BECCS retrofit of existing geothermal plants, owing to discounted costs of pre-existing injection wells, steam fields, and plant equipment.
For a case study based on a geothermal field in New Zealand's Taupō Volcanic Zone (TVZ), we determined that achieving CDR rates of 1 MtCO2/year via new geothermal-BECCS builds would require 62 standard geothermal wells and 790 kt/year of feedstock and result in 511 MWe in installed capacity. In contrast, geothermal-DACCS would need 49 wells and no external fuel source to achieve 1 MtCO2/year scale but result in only 190 MWe in installed capacity. Both pathways are calculated to require similar upfront investment costs at $2.2 billion and $2.3 billion for geothermal-BECCS and geothermal-DACCS respectively.
Although geothermal-DACCS removes CO2 at high rates, its high parasitic load increases the overall decarbonization cost ($187/tCO2). In contrast, when biomass hybridization is considered, geothermal-BECCS has a lower cost of emissions abatement and produces 20 % more electricity than the benchmark geothermal plant. We conclude that this increase in electricity production makes geothermal-BECCS the more cost-effective geothermal-based CDR configuration. Finally, we argue that revenues from net-negative CO2 emissions and increased power production make geothermal-CDR a cost-competitive decarbonization technology.
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