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Thermal power plants are increasingly required to balance power grids by compensating for the intermittent electricity supply from renewable energy resources. As CO 2 capture and storage is integrated with both coal- and gas-fired power plants, it is vital that the emission mitigation technology does not compromise their ability to provide this high-value service. Therefore, developing optimal process operation strategies is vital to maximise both the value provided by and the profitability of these important assets. In this work, we present models of coal- and gas-fired power plants, integrated with a post-combustion CO 2 capture process using a 30 wt% monoethanolamine (MEA) solvent. With the aim to decoupling the power and capture plants in order to facilitate profit maximising behaviour, a multi-period dynamic optimisation problem was formulated and solved using these models. Four distinct scenarios were evaluated: load following, solvent storage, exhaust gas by-pass and variable solvent regeneration (VSR). It was found that for both coal- and gas-fired power plants, the VSR strategy is consistently the most profitable option. The performance of the exhaust by-pass scenario is a strong function of the carbon prices and is only selected at very low carbon prices. The viability of the solvent storage strategy was found to be a strong function of the capital cost associated with the solvent storage infrastructure. When the cost of the solvent tanks has been paid off, then the solvent storage scenario is 3.3% and 8% more profitable than the baseline for the pulverised coal and gas-fired power plants, respectively. Sensitivity analyses showed that, for all strategies, the flexibility benefit declined with reduced carbon and fuel prices, while a “peakier” electricity market, characteristic of one with significant quantities of intermittent renewables deployment, more significantly rewarded flexible operation. [ABSTRACT FROM AUTHOR]

With increasing penetration of intermittent renewable energy into the electricity grid, one can expect thermal power plants to be required to operate in a more dynamic fashion, with more frequent departures from design point operation. However, the application of optimal control strategies can offer solutions to these operational challenges, associated with the integration of the power plant with the capture plant. In this paper a process control strategy is developed in order to select the optimal control variables for a PCC process. In addition, economically efficient control structures for operation of a post-combustion capture process with minimum energy requirements for coal and natural gas power plant are designed. The results have shown that with an appropriate and well-tuned control strategy, it is possible to maintain critical parameters, such as the degree of CO 2 capture, at the desired set-point, even during periods of significant fluctuation in the power plant load and even if based on simple and well established control technologies, such as PID, avoids the need for more risky solutions such as adding solvent storage tanks to the process. [ABSTRACT FROM AUTHOR]

The UK electricity grid is expected to supply a growing electricity demand and also to cope with electricity generation variability as the country pursues a low-carbon future. Molten Salt Reactors (MSRs) could offer a solution to meet this demand thanks to their estimated low capital costs, low operational risk, and promise of reliably dispatchable low-carbon electricity. In the published literature, there is little emphasis placed on estimating or modelling the future impact of MSRs on electricity grids. Previous modelling efforts were limited to quantifying the value of renewable energy sources, energy storage and carbon capture technologies. To date, no study has assessed or modelled MSRs as a competing power generation source for meeting decarbonization targets. Given this gap, the main objective of this paper is to explore the cost benefits for policy makers, consumers, and investors when MSRs are deployed between 2020 and 2050 for electricity generation in the UK. This paper presents results from electricity systems optimization (ESO) modelling of the costs associated with the deployment of 1350 MW e MSRs, from 2025 onwards to 2050, and compares this against a UK grid with no MSR deployment. Results illustrate a minimum economic benefit of £1.25 billion for every reactor installed over this time period. Additionally, an investment benefit occurs for a fleet of these reactors which have a combined net present value (NPV) of £22 billion in 2050 with a payback period of 23 years if electricity is sold competitively to consumers at a price of £60/MWh. [ABSTRACT FROM AUTHOR]

• Detailed sustainability assessment of carbon utilisation processes is crucial. • Potential use of wind energy in transport and power sectors was analysed. • Six countries that vary in grid mixes and gasoline consumption were assessed. • At present, direct use of wind energy to decarbonise the power sector is advisable. Methanol from captured CO 2 provides a more sustainable alternative to gasoline due to its low carbon footprint, yet it requires a large amount of renewable energy that could be used instead to decarbonise the electricity mix. A techno-economic and environmental analysis of methanol produced from captured CO 2 and renewable energy is conducted to shed light on the transportation-power nexus. The investigated scenarios differ in how the carbon-free energy source – electricity from wind – is used to either decarbonise the electricity mix or produce green methanol to displace conventional fossil fuels. The assessment is carried out for six countries that differ in the composition of their electricity mix and gasoline consumption. The results of this holistic assessment show that, at present, decarbonising the electricity grid using renewable energy sources and carbon capture and storage would offer greater environmental benefits, without incurring large changes in direct economic costs, compared to producing methanol from the hydrogenation of captured CO 2. Though this insight might change in the future if the carbon intensity of the mix is reduced and green methanol becomes cheaper, it highlights the need to consider the transportation-power nexus in assessing alternative fuels and thereby prevent shifting of emissions from one sector to another over their life cycle. [ABSTRACT FROM AUTHOR]