Future Low-carbon Electricity System Research Articles

Thermo-economic assessment of flexible nuclear power plants in future low-carbon electricity systems: Role of thermal energy storage

The increasing penetration of intermittent renewable power will require additional flexibility from conventional plants, in order to follow the fluctuating renewable output while guaranteeing security of energy supply. In this context, coupling nuclear reactors with thermal energy storage could ensure a more continuous and efficient operation of nuclear power plants, while at other times allowing their operation to become more flexible and cost-effective. This study proposes options for upgrading a 1610-MWel nuclear power plant with the addition of a thermal energy storage system and secondary power generators. The total whole-system benefits of operating the proposed configuration are quantified for several scenarios in the context of the UK’s national electricity system using a whole-system model that minimises the total system costs. The proposed configuration allows the plant to generate up to 2130MWel during peak load, representing an increase of 32% in nominal rated power. This 520MWel of additional power is generated by secondary steam Rankine cycle systems (i.e., with optimised cycle thermal efficiencies of 24% and 30%) and by utilising thermal energy storage tanks with a total heat storage capacity of 1950MWhth. Replacing conventional with flexible nuclear power plants is found to generate whole-system cost savings between £24.3m/yr and £88.9m/yr, with the highest benefit achieved when stored heat is fully discharged in 0.5 h. At an estimated cost of added flexibility of £42.7m/yr, the proposed flexibility upgrades to such nuclear power plants appears to be economically justified with net system benefits ranging from £4.0m/yr to £31.6m/yr for the examined low-carbon scenarios, provided that the number of flexible nuclear plants in the system is small. This suggests that the value of this technology is system dependent, and that system characteristics should be adequately considered when evaluating the benefits of different flexible nuclear plant configurations and choosing the most cost-effective designs and operational characteristics.

Transient CO2 capture for open-cycle gas turbines in future energy systems

In complex electricity systems with a varied generation mix, the security of supply is important, and the quick-response nature of gas turbines is invaluable in providing system flexibility. Accompanied with post-combustion capture (PCC) of CO2, gas turbines can support the transition to a future low-carbon electricity system. This study presents the development and validation of a dynamic rate-based model of the benchmark CO2 absorption process, using 30 wt% monoethanolamine (MEA). The model is scaled up from pilot-scale to match the flue gas output from a modern small-scale gas turbine operating in open-cycle configuration. Simulations of various flexible operating scenarios shows the rapid transitioning between full and partial load is beneficial in delivering higher time-averaged CO2 capture rates, compared to the Baseload scenario where the PCC system is operated at full load for 5 h. Maintaining a constant liquid/gas (L/G) ratio results in 90.01% CO2 capture; however, this increases the energy demand due to constant reboiler steam flowrate. To compensate, the steam flowrate is also ramped, resulting in a small decrease in reboiler duty compared to the Baseload scenario. Importantly, no negative energy or capture rate related issues to highly-transient PCC operation are found.

The cost of a future low-carbon electricity system without nuclear power – the case of Sweden

To achieve the goal of deep decarbonization of the electricity system, more and more variable renewable energy (VRE) is being adopted. However, there is no consensus among researchers on whether the goal can be accomplished without large cost escalation if nuclear power is excluded in the future electricity system. In Sweden, where nuclear power generated 41% of the annual electricity supply in 2014, the official goal is 100% renewable electricity production by 2040. Therefore, we investigate the cost of a future low-carbon electricity system without nuclear power for Sweden. We model the European electricity system with a focus on Sweden and run a techno-economic cost optimization model for capacity investment and dispatch of generation, transmission, storage and demand-response, under a CO2 emission constraint of 10 g/kWh. Our results show that there are no, or only minor, cost benefits to reinvest in nuclear power plants in Sweden once the old ones are decommissioned. This holds for a large range of assumptions on technology costs and possibilities for investment in additional transmission capacity. We contrast our results with the recent study that claims severe cost penalties for not allowing nuclear power in Sweden and discuss the implications of methodology choice.

Supplementary Data: The cost of a future low-carbon electricity system without nuclear power – the case of Sweden

Supplementary Data: The cost of a future low-carbon electricity system without nuclear power – the case of Sweden

The role of floating offshore wind in a renewable focused electricity system for Great Britain in 2050

Floating offshore wind energy is an emerging technology that provides access to new wind generation sites allowing for a diversified wind supply in future low carbon electricity systems. We use a high spatial and temporal resolution power system optimisation model to explore the conditions that lead to the deployment of floating offshore wind and the effect this has on the rest of the electricity system for Great Britain in 2050. We perform a sensitivity analysis on three dimensions: total share of renewables, floating offshore costs and the impact of waves on operation. We find that all three impact the deployment of floating offshore wind energy. A clear competition between floating offshore wind and conventional offshore wind is demonstrated, with less impact on other renewable sources. It is shown that floating wind is used to provide access to greater spatial diversification. Further, access to more distant regions also affects the optimal placement of conventional offshore wind, as spatial diversification is spread between floating and bottom-mounted sites.

The Future of Low-Carbon Electricity

We review future global demand for electricity and major technologies positioned to supply it with minimal greenhouse gas (GHG) emissions: renewables (wind, solar, water, geothermal, and biomass), nuclear fission, and fossil power with CO2 capture and sequestration. We discuss two breakthrough technologies (space solar power and nuclear fusion) as exciting but uncertain additional options for low-net GHG emissions (i.e., low-carbon) electricity generation. In addition, we discuss grid integration technologies (monitoring and forecasting of transmission and distribution systems, demand-side load management, energy storage, and load balancing with low-carbon fuel substitutes). For each topic, recent historical trends and future prospects are reviewed, along with technical challenges, costs, and other issues as appropriate. Although no technology represents an ideal solution, their strengths can be enhanced by deployment in combination, along with grid integration that forms a critical set of enabling technologies to assure a reliable and robust future low-carbon electricity system.

Unlocking New Sources of Flexibility: CLASS: The World's Largest Voltage-Led Load-Management Project

The Significant growth of wind and photovoltaic generation experienced in many countries around the world will soon challenge the ability of transmission system operators (TSOs) to guarantee the security of supply. To cope with such future low-carbon electricity systems, it is imperative to increase the portfolio of flexibility sources in a cost-effective and sustainable manner. This is likely to require exploring solutions beyond the use of traditional players connected at higher voltages, such as fast-acting generation plants and large customers.

Environmental impacts of future low-carbon electricity systems: Detailed life cycle assessment of a Danish case study

The need to reduce dependency on fossil resources and to decrease greenhouse gas (GHG) emissions is driving many countries towards the implementation of low-carbon electricity systems. In this study the environmental impact of a future (2030) possible low-carbon electricity system in Denmark was assessed and compared with the current situation (2010) and an alternative 2030 scenario using life cycle assessment (LCA). The influence on the final results of the modeling approach used for (i) electricity import, (ii) biomass resources, and (iii) the cogeneration of heat and power was discussed. The results showed that consumption of fossil resources and global warming impacts from the Danish electricity sector could be reduced significantly compared with 2010. Nevertheless, a reduction in GHG may be at the expense of other environmental impacts, such as the increased depletion of abiotic resources. Moreover, the results were very dependent upon biomass origin: when agricultural land was affected by biomass import, and land use changes and transportation were included, GHG emissions from imported biomass were comparable to those from fossil fuels. The results were significantly influenced by the modeling approach regarding the import of electricity, biomass provision, and the allocation between heat and power in cogeneration plants. As the importance of all three aspects is likely to increase in the future, transparency in LCA modeling is critical. Characterized impacts for Danish power plants in 2010 and 2030 (including corresponding electricity supply mixes) were provided, thus enabling future LCA studies to include appropriately impacts from the Danish electricity sector.

SunShot Solar Power Reduces Costs and Uncertainty in Future Low-Carbon Electricity Systems

The United States Department of Energy's SunShot Initiative has set cost-reduction targets of $1/watt for central-station solar technologies. We use SWITCH, a high-resolution electricity system planning model, to study the implications of achieving these targets for technology deployment and electricity costs in western North America, focusing on scenarios limiting carbon emissions to 80% below 1990 levels by 2050. We find that achieving the SunShot target for solar photovoltaics would allow this technology to provide more than a third of electric power in the region, displacing natural gas in the medium term and reducing the need for nuclear and carbon capture and sequestration (CCS) technologies, which face technological and cost uncertainties, by 2050. We demonstrate that a diverse portfolio of technological options can help integrate high levels of solar generation successfully and cost-effectively. The deployment of GW-scale storage plays a central role in facilitating solar deployment and the availability of flexible loads could increase the solar penetration level further. In the scenarios investigated, achieving the SunShot target can substantially mitigate the cost of implementing a carbon cap, decreasing power costs by up to 14% and saving up to $20 billion ($2010) annually by 2050 relative to scenarios with Reference solar costs.