Chechet Biliyok

Calcium looping with inherent energy storage for decarbonisation of coal-fired power plant

Implementation of carbon capture and storage, nuclear power stations and wide utilisation of renewable energy sources have been identified as capable of reducing around 42% of the energy sector’s cumulative CO2 emissions between 2009 and 2050. In scenarios assuming high shares of renewable energy sources in the energy portfolio, energy storage technologies and the remaining power generating assets would be required to flexibly balance energy supply and demand. With nuclear power plants operating at base load, this task would be handled by flexible fossil fuel power plants with CO2 capture. However, mature CO2 capture systems were shown to impose high efficiency penalties (8–12.5% points) and are better suited for base-load operation. An emerging calcium looping process, which has also been considered for energy storage, has been found to offer lower efficiency penalties (5–8% points). This study presents a concept of the calcium looping process with inherent energy storage for decarbonisation of the coal-fired power plant. Analysis has revealed that the possible routes for energy storage in this process include CaO/CaCO3 solids storage, CaO/Ca(OH)2 solids storage and cryogenic O2 storage systems. Comparison of the CaO/CaCO3 storage and cryogenic O2 storage systems revealed that implementation of the latter would result in higher turndown of the entire system and would offer higher energy density. Also, the hydration reaction was found to improve the energy density of the CaO/CaCO3 energy storage system by 57.4%, from 307.2 kWth h m−3 to 483.6 kWth h m−3. Economic evaluation of the proposed concepts revealed that application of the cryogenic O2 storage system in the calcium looping CO2 capture process has the potential to increase the profitability of the integrated system, even over the reference coal-fired power plant without CO2 capture.

Techno-Economic Analysis of a Natural Gas Combined Cycle Power Plant with CO2 Capture

Abstract Power generation via natural gas is projected to increase over the next decade. CO2 capture would be required to mitigate the associated emissions. Integrating a capture plant to power plants can be explored via process simulation. Hence, high fidelity models of a natural gas combined cycle power plant and a post-combustion capture plant were built – a 440MW power plant model that is tuned and validated with data from GE’s GateCycle®, and a rate-based capture plant model that is scaled up from a previously validated model. Along with a suitably sized compression train, the plants are integrated for 90% CO2 capture. Net power output is observed to fall by 14%, but cooling water demand increases by 33%. A 40% exhaust gas recirculation (EGR) results in a marginal recovery in output, but also raises cooling water demand further. A redesign of the steam cycle to account for integration would potentially improve performance. Economic analysis is performed via a bottom-up approach. The integrated plant overnight cost is determined to be 45% higher than cost of the power plant without capture, but is only 43% higher with EGR. The cost of electricity also increases by 41% for the integrated plant, but by only 38% with EGR. Lastly, the cost of CO2 avoided is estimated to be €69 per ton of CO2, but reduces to €63 with EGR.

Dynamic Simulation and Control of Post-combustion CO2 Capture with MEA in a Gas Fired Power Plant

This paper presents a dynamic model of a post combustion CO2 capture plant via chemical absorption using monoethanolamine (MEA) for natural gas combined cycle (NGCC) power plants. Insight regarding the process dynamics due to various disturbances caused by the operation of the power plant is presented and a control structure is proposed, based on heuristics. The performance of the proposed control scheme was evaluated by changing the flue gas flow rate which is commonly induced in the operation of power plants such as during start-up, shutdown and cyclic loading. Consideration has also been given to the variations to the control tuning due to the lower composition of CO2 in NGCC plant compared to coal fired power plants. The results have shown that with the implementation of the proposed control scheme, the flexible operation of the power plant in combination with the capture plant can be maintained.

Dynamic Validation of Model for Post-Combustion Chemical Absorption CO2 Capture Plant

Abstract Dynamic modelling for post-combustion CO 2 capture using monoethanolamine (MEA) solvent has been validated at steady state in the past. This paper presents a dynamic validation. The absorber and regenerator were modelled using the two-film theory in gPROMS®. Electrolyte NRTL model in Aspen Properties® is used to describe the chemical equilibrium and vapour-liquid equilibrium. The CO 2 capture process was simulated. The temperature profile of the absorber, the capture level and the regenerator duty were compared with pilot plant data logs. It is observed that the model satisfactorily predicts the behaviour of the pilot plant due to a number of process inputs and disturbances, producing trends in close agreement with the data logs.

Trilateral Flash Cycle for Recovery of Power from a Finite Low-Grade Heat Source

Abstract The trilateral flash cycle (TFC) among the heat recovery-to-power technologies presents a great potential for development. Unlike the Rankine cycle, the proposed TFC does not evaporate its working fluid during the heating phase; instead expands it, from the saturated liquid condition, as a two-phase mixture bypassing the isothermal boiling phase. This paper examines the feasibility of interfacing the TFC system for low-grade heat recovery-to-power generation using thermal energy from hot produced water at constant flow rate from a gas well. The corresponding thermodynamic processes of the TFC thermal power plant were thermodynamically modelled and implemented. The results depict that the thermal efficiency of the proposed TFC employing isobutane as the working fluid is 13.6 - 17.1 % over the examined cycle high temperatures of 363 - 393 K, which is 30 - 40 % improvement over organic Rankine cycle and the cycle exergy efficiency is 81.1 %.

Rate-based Modelling of Chilled Ammonia Process (CAP) for CO2 Capture

Abstract Chilled ammonia process (CAP) has been identified as a promising alternative to the monoethanolamine based capture process for post-combustion CO 2 capture. Therefore, a full-scale rate-based CAP capture plant model has been developed. First, the aqueous NH 3 process was modelled in Aspen Plus and validated with pilot-plant data. The model was modified to meet the CAP operating conditions, and then scaled-up to process the flue gas from 660 MW el coal-fired power plant. The full-scale rate-based CAP model showed a substantial performance improvement through reducing the energy requirement for solvent regeneration by 27 % compared to the reference MEA process.