This paper reviews the classification schemes used for bottom-up energy system modelling and proposes a novel one as re-elaboration of the previous schemes. Moreover, this paper identifies that the main challenges of this research field rotate around the concept of resolution. A matrix of challenges in which four main fields are identified: resolution in time, in space, in techno-economic detail and in sector-coupling. These main fields are divided into different levels of resolution: low, medium and high. The use of a low resolution introduces errors in the modelling as demonstrated by different studies. Several existing bottom-up energy system models are reviewed in order to classify them according to the proposed approach and map them through the proposed matrix. 13 different models are analyzed in the category of bottom-up short-term and 9 as bottom-up long-term energy system models. The following mapping shows how several models reach a high level of resolution in one or more than one area. However, the ultimate challenge is the simultaneous achievement of high resolution in all these fields. The literature review has shown how this final aim is not reached by any model at the current stage and it highlights the gap and weaknesses of this branch of research and the direction versus which is important to work to improve this type of modelling.

This work compares the part load techno-economic performance of CO₂ capture from a combined cycle gas turbine (CCGT) using a membrane configuration with selective CO₂ recycle and using monoethanolamine (MEA) solvent, under the assumption of flexible power plant dispatch. This is the first time that the techno-economic performance of CO₂ capture technologies is compared assuming a flexible dispatch profile, and the assessment was done using a comprehensive, new, part load assessment approach. Analyzing the part load performance of CO₂ capture and storage (CCS) technologies is relevant because of significant changes in our power systems, dramatically reducing the utilization of thermal power plants. The technical performance of the configurations with and without CCS was simulated at steady state, at operating points between maximum continuous rating (100% gas turbine loading) and minimum stable load (35% gas turbine loading). The performance at these operating points was then aggregated into weighted averages to produce single performance indicators (specific CO₂ intensity, specific primary energy per tonne of CO₂ avoided (SPECCA), and levelized cost of electricity (LCOE)) over the dispatch profile of the power plant. The technical performance of the MEA configuration was favorable over the membrane configuration over the whole CCGT loading range. The MEA SPECCA increased from 3.02 GJ/(t of CO₂) at 100% GT loading to 3.65 GJ/(t of CO₂) at 35% GT loading; the membrane SPECCA increased from 3.35 to 4.20 GJ/(t of CO₂). The higher SPECCA of the membrane configuration is caused by the reduced gas turbine efficiency, due to the selective recycling of CO₂ to the GT. When equal GT efficiency was assumed for combustion with normal air and with CO₂ enriched air, the membranes' technical performance was comparable with that of MEA. The capital costs of the CCGT with membrane configuration were 35% higher than the CCGT with MEA configuration. That, and the 6 year replacement frequency of the membranes, led the membrane LCOE to be 10 €/(MW h) higher than the MEA LCOE, when calculated with the part load approach. The membrane LCOE was 8 €/(MW h) higher when a full load was assumed. The new part load approach proved instrumental in highlighting performance (differences) at flexible dispatch conditions and aggregating those into easy to understand performance indicators.

An approach for the techno-economic assessment of power plants with and without carbon capture and storage (CCS) is proposed. A state-of-the-art natural gas combined cycle (NGCC) power plant is selected equipped with post-combustion CO₂ capture technology (MEA). The technoeconomic indicators are calculated using both the conventional and part load approaches. The economic results also show significant differences between the full load and the part load approaches. The results show that the levelized cost of electricity (LCOE) of gas-based power generation with CCS will more likely be above 100 €/MWh than below this value. This inherently also leads to an increase of the cost of CO₂ avoided in the order of 20-100%. The observed differences between the full load and part load approaches showcase the necessity for including real dispatch profiles when calculating the technoeconomic performance of CCS power.