Neo Khesa's research while affiliated with University of the Witwatersrand and other places

Please cite this article as: N. Khesa, J. Mulopo, B. Oboirien, ASPEN Plus® reassessment of efficiency penalties associated with a pulverised coal oxy-combustion power plant-A case study, Case Studies in Chemical and Environmental Engineering (2022), doi: https://doi. Abstract 14 15 The ASPEN Plus V8.4 was used to model air-and oxy-combustion plants and determine the thermal 16 efficiency penalty associated with retrofits, which was then compared to the thermal efficiency penalty 17 established in the literature. Additionally, this paper investigates the feasibility of offsetting the efficiency 18 penalty through the use of reaction heat from flue gas desulphurization (FGD), as all previous research on 19 the subject has ignored both the reaction heat generated by the FGD unit and the chemical exergy of the 20 FGD wastewater. Finally, a heat integration study is done to determine the feasibility of preheating boiler 21 feed water during the steam cycle utilizing compression heat generated by the air separation unit (ASU) 22 and CPU (compression and purification unit) compressors. Thermal efficiency penalty was determined to 23 be 9.24 % in this study, while the theoretically bare minimum efficiency penalty was determined to be 3 24 %. Additionally, it was determined that by combining the compression and steam cycles, net thermal 25 efficiency may be increased by 0.679 %. 26

The ASPEN Plus V8.4 was used to model air- and oxy-combustion plants and determine the thermal efficiency penalty associated with retrofits, which was then compared to the thermal efficiency penalty established in the literature. Additionally, this paper investigates the feasibility of offsetting the efficiency penalty through the use of reaction heat from flue gas desulphurization (FGD), as all previous research on the subject has ignored both the reaction heat generated by the FGD unit and the chemical exergy of the FGD wastewater. Finally, a heat integration study is done to determine the feasibility of preheating boiler feed water during the steam cycle utilizing compression heat generated by the air separation unit (ASU) and CPU ( compression and purification unit) compressors. Thermal efficiency penalty was determined to be 9.24 % in this study, while the theoretically bare minimum efficiency penalty was determined to be 3 %. Additionally, it was determined that by combining the compression and steam cycles, net thermal efficiency may be increased by 0.679 %.

In this paper, a high temperature coelectrolysis power to gas (LTE PtG) setup was developed that was fed a stereotypical feed in CO2 one could acquire from carbon capture and sequestration (CCS) retrofit. The electrolyzer was fed an equimolar 10 kmol/s feed in water and CO2 and the electrolyzer product was composed of 38.80 mole% CO2, 30.96 mole% CO, and 30.24 mole% H2 for a syngas conversion of 43.8%. The product from the methanation unit was only composed of 21.38 mole% CH4, with the rest (76.53 mole%) being predominantly CO2. The methanation unit was composed of only one Sabatier reactor operating at 313°C, which had 90% of its product recycled back to the front end of the unit. The electrolyzer was found to have a LHV efficiency of 31.49%, and the entire HTCE PtG process was found to have an efficiency of 74.31% with methane storage and 76.49% without methane storage. A novel adaptation was developed on previous work on the exergy analysis for flow‐sheet simulators which can be used for cyclic and noncyclic processes. The procedure was determined to be accurate, with irreversibilities determined across all the major subunits found to equal the irreversibility around the processes a whole. The electrolyzer was found to be responsible for the majority of the irreversibility within the setup, and this was attributed to the fact that water electrolysis is a very energy intensive process. The exergy efficiency of the electrolyzer was found to be 87.07% and that of the entire LTE PtG processes was found to be 84% with methane storage, and 87% without methane storage. In the end, it was determined that HTCE is unsuitable for the production of methane via retrofit with a methanation unit, and that it would be better suited for the production of liquid hydrocarbon fuels with much higher molecular carbon to hydrogen ratios.