Browsing by Author "Biliyok, Chechet"

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    Evaluation of efficiency improvements and performance of coal-fired power plants with post-combustion CO2 capture
    (Cranfield University, 2016-03) Hanak, Dawid P.; Manovic, Vasilije; Biliyok, Chechet
    The power sector needs to be decarbonised by 2050 to meet the global target for greenhouse gas emission reduction and prevent climate change. With fossil fuels expected to play a vital role in the future energy portfolio and high efficiency penalties related to mature CO2 capture technologies, this research aimed at evaluating the efficiency improvements and alternate operating modes of the coal-fired power plants (CFPP) retrofitted with post-combustion CO2 capture. To meet this aim, process models of the CFPPs, chilled ammonia process (CAP) and calcium looping (CaL) were developed in Aspen Plus® and benchmarked against data available in the literature. Also, the process model of chemical solvent scrubbing using monoethanolamine (MEA) was adapted from previous studies. Base-load analysis of the 580 MWel CFPP retrofits revealed that if novel CAP retrofit configurations were employed, in which a new auxiliary steam turbine was coupled with the boiler feedwater pump for extracted steam pressure control, the net efficiency penalty was 8.7–8.8% points. This was close to the 9.5% points in the MEA retrofit scenario. Conversely, CaL retrofit resulted in a net efficiency penalty of 6.7–7.9% points, depending on the fuel used in the calciner. Importantly, when the optimised supercritical CO2 cycle was used instead of the steam cycle for heat recovery, this figure was reduced to 5.8% points. Considering part-load operation of the 660 MWel CFPP and uncertainty in the process model inputs, the most probable net efficiency penalties of the CaL and MEA retrofits were 9.5% and 11.5% points, respectively. Importantly, in the CaL retrofit scenarios, the net power output was found to be around 40% higher than that of the CFPP without CO2 capture and double than that for the MEA retrofit scenario. Such performance of the CaL retrofit scenario led to higher profit than that of the 660 MWel CFPP without CO2 capture, especially if its inherent energy storage capability was utilised. Hence, this study revealed that CaL has the potential to significantly reduce the efficiency and economic penalties associated with mature CO2 capture technologies.
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    Process analysis and improvement of a Claus unit of an existing gas plant
    (Cranfield University, 2016-05) Gharsalla, Khaled R. M.; Yeung, Hoi; Biliyok, Chechet
    This research is a part of Master degree research programme at Cranfield University to study Claus process and perform process analysis on an existing Sulphur recovery unit in a gas plant. The Mellitah Plant, in Western Libya, is a gas plant designed to treat raw gas and condensate from offshore gas fields in several processing units where the sour gas (H2S, CO2, COS, SC2) is removed to meet the international emission standard, in order to control the emission and pollution from the flue gas. The acid gases are treated in Claus unit where H2S is converted to sulphur in multi-reaction steps. These reactions start in a combustion reaction zone, thermal reactor, to produce a suitable mixture of H2S to SO2. The mixture reacts in Claus catalytic reactors to produce sulphur vapour. The sulphur vapour is condensed in multi-condensing steps after each catalytic reactor. The ultimate aim of this research is to carry out the process analysis for Claus unit in order to recover the waste energy to increase the plant productivity, minimise the use of the plant utilities, and decrease the environmental pollution. A process model of the plant was developed and validated in Aspen HYSYS. The process was then analysed, the analysis has resulted in a significant increase in Claus unit overall conversion ratio which has increased from 61% to 97.63% H2S base. Consequently, Claus unit productivity has increased by approximately 1.72 times. In addition, a higher amount of energy is recovered in a form of heat by heating the boiler feed water to produce both high pressure steam in the waste heat boiler and low pressure steam in 1st and 2nd sulphur condensers. Both high pressure and low pressure steam total production are increased by 1.5 times. All this has been achieved at high conversion ratio number of 2 in tail gas which represents optimum O2/H2S ratio in the thermal reactor feed and the high conversion number can be kept in between 1.5 to 3 during plant normal operation.
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    Process modelling and simulation of degradation of 2-amino-2-methyl-1-propanol (AMP) capture plant
    (Elsevier, 2017-08-18) Osagie, Ebuwa; Biliyok, Chechet; Di Lorenzo, Giuseppina; Manovic, Vasilije
    The presence of contaminants in the flue gas stream such as O2, CO2, SOX, and NOX can cause solvent degradation in solvent-based CO2 capture processes. In this study, the major degradation products reactions of the AMP-based CO2 capture process has been included in the Aspen Plus® V8.4 simulation software using equilibrium reactions. Assessing the solvent degradation, solvent concentration and flowrate were varied. The results showed that the AMP losses reduced by decreasing solvent flowrate and concentration. Largest energy savings are observed when increasing concentration up to 34 wt. %.
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    Study of power plant with carbon dioxide capture ability through modelling and simulation
    (Cranfield University, 2013-11) Biliyok, Chechet; Yeung, Hoi
    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.
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    A systematic review of keys challenges of CO2 transport via pipelines
    (Elsevier, 2017-06-27) Onyebuchi, Victor E.; Kolios, Athanasios; Hanak, Dawid P.; Biliyok, Chechet; Manovic, Vasilije
    Transport of carbon dioxide (CO2) via pipeline from the point of capture to a geologically suitable location for either sequestration or enhanced hydrocarbon recovery is a vital aspect of the carbon capture and storage (CCS) chain. This means of CO2 transport has a number of advantages over other means of CO2 transport, such as truck, rail, and ship. Pipelines ensure continuous transport of CO2 from the capture point to the storage site, which is essential to transport the amount of CO2 captured from the source facilities, such as fossil fuel power plants, operating in a continuous manner. Furthermore, using pipelines is regarded as more economical than other means of CO2 transport The greatest challenges of CO2 transport via pipelines are related to integrity, flow assurance, capital and operating costs, and health, safety and environmental factors. Deployment of CCS pipeline projects is based either on point-to-point transport, in which case a specific source matches a specific storage point, or through the development of pipeline networks with a backbone CO2 pipeline. In the latter case, the CO2 streams, which are characterised by a varying impurity level and handled by the individual operators, are linked to the backbone CO2 pipeline for further compression and transport. This may pose some additional challenges. This review involves a systematic evaluation of various challenges that delay the deployment of CO2 pipeline transport and is based on an extensive survey of the literature. It is aimed at confidence-building in the technology and improving economics in the long run. Moreover, the knowledge gaps were identified, including lack of analyses on a holistic assessment of component impurities, corrosion consideration at the conceptual stage, the effect of elevation on CO2 dense phase characteristics, permissible water levels in liquefied CO2, and commercial risks associated with project abandonment or cancellation resulting from high project capital and operating costs.
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    Techno-economic evaluation of the 2-amino-2-methyl-1-propanol (AMP) process for CO2 capture from natural gas combined cycle power plant
    (Elsevier, 2018-02-04) Osagie, Ebuwa; Biliyok, Chechet; Di Lorenzo, Giuseppina; Hanak, Dawid P.; Manovic, Vasilije
    It is widely accepted that emissions of CO2, which is a major greenhouse gas, are the primary cause of climate change. This has led to the development of carbon capture and storage (CCS) technologies in which CO2 is captured from large-scale point sources such as power plants. However, retrofits of carbon capture plants result in high efficiency penalties, which have been reported to fall in the range of 7–12% points in the case of post-combustion capture from natural gas-fired power plants. Therefore, a reduction of these efficiency losses is a high priority in order to deploy CCS at a large scale. At the moment, chemical solvent scrubbing using amines, such as monoethanolamine (MEA), is considered as the most mature option for CO2 capture from fossil fuel-fired power plants. However, due to high heat requirements for solvent regeneration, and thus high associated efficiency penalties, the use of alternative solvents has been considered to reduce the energy demand. In this study, a techno-economic assessment of the post-combustion CO2 capture process using 2-amino-2-methyl-1-propanol (AMP) for decarbonisation of a natural gas combined cycle (NGCC) power plant was performed. The thermodynamic assessment revealed that the AMP-based process resulted in 25.6% lower reboiler duty compared to that of the MEA-based process. This was primarily because the AMP solvent can be regenerated at a higher temperature (140 °C) and pressure (3.5 bar) compared to that of MEA (120 °C and 1.8 bar). Furthermore, the efficiency penalty due to the retrofit of the AMP-based process with the natural gas combined cycle power plant was estimated to be 7.1% points, compared to 9.1% points in the case of integration with the MEA-based process. Regardless of the superior thermodynamic performance, the economic performance of the AMP-based process was shown to be better than that of the MEA-based process only for make-up rates below 0.03%. Therefore, use of AMP as a solvent in chemical solvent scrubbing may not be the most feasible option from the economic standpoint, even though it can significantly reduce the efficiency penalty associated with CO2 capture from NGCCs.