Given the growing worldwide interest in fossil fuels on one hand and mitigation of climate change on the other hand, it is necessary to research into new technologies as Carbon Capture and Storage. This technology became a matter of interest as an option to diminish greenhouse gas emissions of power plants. It is essential to find out about the costs of Carbon Capture and Storage and expected future costs of power plants with CCS. Impact of this techology is not only in the sphere of capital and operational costs, but it also influences power plant efficiency and fuel consumption in negative way. Analysis of reductions in the costs of this technology as a result of learning-by-doing is observed on Experience Curves. This study observes influence of CCS on costs of mainly PC, IGCC and NGCC type of power plant. CCS technology has positive impact not only on environment, but it is possible to assess Enhanced Oil, Methane or Gas Recovery, which can partly offset costs of this technology.

With an increased urgency for global action towards climate change mitigation, this research was undertaken with the aim of evaluating post-combustion CO2 capture as an emission abatement strategy for gas-fired power plants. A dynamic rate-based model of a capture plant with MEA solvent was built, with imposed chemical equilibrium, and validated at pilot scale under transient conditions. The model predicted plant behaviour under multiple process inputs and disturbances. The validated model was next used to analyse the process and it was found that CO2 absorption is mass transfer limited. The model was then improved by explicitly adding reactions rate in the model continuity, the first such dynamic model to be reported for the capture process. The model is again validated and is observed to provide better predictions than the previous model. Next, high fidelity models of a gas-fired power plant, a scaled-up capture plant and a compression train were built and integrated for 90% CO2 capture. Steam for solvent regeneration is extracted from the power plant IP/LP crossover pipe. Net efficiency drops from 59% to 49%, with increased cooling water demand. A 40% exhaust gas recirculation resulted in a recovery of 1% efficiency, proving that enhanced mass transfer in the capture plant reduces solvent regeneration energy demands. Economic analysis reveals that overnight cost increases by 58% with CO2 capture, and cost of electricity by 30%. While this discourages deployment of capture technology, natural gas prices remain the largest driver for cost of electricity. Other integration approaches – using a dedicated boiler and steam extraction from the LP steam drum – were explored for operational flexibility, and their net efficiencies were found to be 40 and 45% respectively. Supplementary firing of exhaust gas may be a viable option for retrofit, as it is shown to minimise integrated plant output losses at a net efficiency of 43.5%. Areas identified for further study are solvent substitution, integrated plant part load operation, flexible control and use of rotating packed beds for CO2 capture.

With an increased urgency for global action towards climate change mitigation, this research was undertaken with the aim of evaluating post-combustion CO2 capture as an emission abatement strategy for gas-fired power plants. A dynamic rate-based model of a capture plant with MEA solvent was built, with imposed chemical equilibrium, and validated at pilot scale under transient conditions. The model predicted plant behaviour under multiple process inputs and disturbances. The validated model was next used to analyse the process and it was found that CO2 absorption is mass transfer limited. The model was then improved by explicitly adding reactions rate in the model continuity, the first such dynamic model to be reported for the capture process. The model is again validated and is observed to provide better predictions than the previous model. Next, high fidelity models of a gas-fired power plant, a scaled-up capture plant and a compression train were built and integrated for 90% CO2 capture. Steam for solvent regeneration is extracted from the power plant IP/LP crossover pipe. Net efficiency drops from 59% to 49%, with increased cooling water demand. A 40% exhaust gas recirculation resulted in a recovery of 1% efficiency, proving that enhanced mass transfer in the capture plant reduces solvent regeneration energy demands. Economic analysis reveals that overnight cost increases by 58% with CO2 capture, and cost of electricity by 30%. While this discourages deployment of capture technology, natural gas prices remain the largest driver for cost of electricity. Other integration approaches – using a dedicated boiler and steam extraction from the LP steam drum – were explored for operational flexibility, and their net efficiencies were found to be 40 and 45% respectively. Supplementary firing of exhaust gas may be a viable option for retrofit, as it is shown to minimise integrated plant output losses at a net efficiency of 43.5%. Areas identified for further study are solvent substitution, integrated plant part load operation, flexible control and use of rotating packed beds for CO2 capture.

Selective Exhaust Gas Recirculation (S-EGR) consists of selectively transferring CO2 from the exhaust gas stream of a gas-fired power plant into the air stream entering the gas turbine compressor. Unlike in “non-selective” Exhaust Gas Recirculation (EGR) technology, recirculation of, principally, nitrogen does not occur, and the gas turbine still operates with a large excess of air. Two configurations are proposed: one with the CO2 transfer system operating in parallel to the post-combustion carbon capture (PCC) unit; the other with the CO2 transfer system operating downstream of, and in series to, the PCC unit. S-EGR allows for higher CO2 concentrations in the flue gas of approximately 13-14 vol%, compared to 6.6 vol% with EGR at 35% recirculation ratio. The oxygen levels in the combustor are approximately 19 vol%, well above the minimum limit of 16 vol% with 35% EGR reported in literature. At these operating conditions, process model simulations show that the current class of gas turbine engines can operate without a significant deviation in the compressor and the turbine performance from the design conditions. Compressor inlet temperature and CO2 concentration in the working fluid are critical parameters in the assessment of the effect on the gas turbine net power output and efficiency. A higher turbine exhaust temperature allows the generation of additional steam which results in a marginal increase in the combined cycle net power output of 5% and 2% in the investigated configurations with S-EGR in parallel and S-EGR in series, respectively. With aqueous monoethanolamine scrubbing technology, S-EGR leads to operation and cost benefits. S-EGR in parallel operating at 70% recirculation, 97% selective CO2 transfer efficiency and 96% PCC efficiency results in a reduction of 46% in packing volume and 5% in specific reboiler duty, compared to air-based combustion CCGT with PCC, and of 10% in packing volume and 2% in specific reboiler duty, compared to 35% EGR. S-EGR in series operating at 95% selective CO2 transfer efficiency and 32% PCC efficiency results in a reduction of 64% in packing volume and 7% in specific reboiler duty, compared to air-based, and of 40% in packing volume and 4% in specific reboiler duty, compared to 35% EGR. An analysis of key performance indicators for selective CO2 transfer proposes physical adsorption in rotary wheel systems as an alternative to selective CO2 membrane systems. A conceptual design assessment with two commercially available adsorbent materials, activated carbon and Zeolite X13, shows that it is possible to regenerate the adsorbent with air at near ambient temperature and pressure. Yet, a significant step change in adsorbent materials is necessary to design rotary adsorption systems with dimensions comparable to the largest rotary gas/gas heat exchanger used in coal-fired power plants, i.e. approximately 24 m diameter and 2 m height. An optimisation study provides guidelines on the equilibrium parameters for the development of materials. Finally, a technical feasibility study of configuration options with rotary gas/gas heat exchangers shows that cooling water demand around the post-combustion CO2 capture system can be drastically reduced using dry cooling systems where gas/gas heat exchangers use ambient air as the cooling fluid. Hybrid cooling configurations reduce cooling and process water demand in the direct contact cooler of a wet cooling system by 67% and 35% respectively, and dry cooling configurations eliminate the use of process and cooling water and achieve adequate gas temperature entering the absorber.