Process modelling and simulation of degradation of 2-amino-2-methyl-1-propanol (AMP) capture plant

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. %

Techno-economic evaluation of the 2-amino-2-methyl-1-propanol (AMP) process for CO2 capture from natural gas combined cycle power plant

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

A systematic review of keys challenges of CO2 transport via pipelines

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

Improved Smell Agent Optimization Sizing Technique Algorithm for a Grid-Independent Hybrid Renewable Energy System

This chapter discuss an improvement on the novel computational intelligent algorithm using the smell phenomenon. In the standard smell agent optimization algorithm, the olfactory capacity is constant thereby assuming that every smell agent has the same sensing capacity. In the improved smell agent optimization algorithm, that is changed to account for the difference in smell agent capacity. The algorithm was run against the standard smell agent optimization on Matlab to find the best HRES design using annual cost, Levelized cost of electricity (LCE), loss of power supply probability (LPSP) and excess energy. It was shown after the comparative analysis that there was a 79%, 99.9% and 53.4% improvement for annual cost, LCE and LPSP respectively. Statistically, results showed that the iSAO obtained the most cost effective HRES design compared to the benchmarked algorithms

A systematic review of key challenges of CO2 transport via pipelines

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

Carbon capture from natural gas combined cycle power plants: Solvent performance comparison at an industrial scale

Natural gas is an important source of energy. This article addresses the problem of integrating an existing natural gas combined cycle (NGCC) power plant with a carbon capture process using various solvents. The power plant and capture process have mutual interactions in terms of the flue gas flow rate and composition vs. the extracted steam required for solvent regeneration. Therefore, evaluating solvent performance at a single (nominal) operating point is not indicative and solvent performance should be considered subject to the overall process operability and over a wide range of operating conditions. In the present research, a novel optimization framework was developed in which design and operation of the capture process are optimized simultaneously and their interactions with the upstream power plant are fully captured. The developed framework was applied for solvent comparison which demonstrated that GCCmax, a newly developed solvent, features superior performances compared to the monoethanolamine baseline solvent

Review of dynamic modelling, system identification and control scheme in solvent-based post-combustion carbon capture process

Solvent-based post-combustion carbon capture (PCC) process is widely viewed as the most viable option for reducing CO 2 emission. This technology has been deployed globally and many researches have been conducted in this area. In this paper, current status of dynamic modelling, system identification and control scheme of solvent-based PCC process is reviewed. Different research directions of these areas are discussed to conclude the existing challenges. Based on this, this paper is also trying to provide potential solutions as possible pathways for flexible and economical operation

Process intensification for post combustion CO₂ capture with chemical absorption: a critical review

The concentration of CO₂ in the atmosphere is increasing rapidly. CO₂ emissions may have an impact on global climate change. Effective CO₂ emission abatement strategies such as carbon capture and storage (CCS) are required to combat this trend. Compared with pre-combustion carbon capture and oxy-fuel carbon capture approaches, post-combustion CO₂ capture (PCC) using solvent process is one of the most mature carbon capture technologies. There are two main barriers for the PCC process using solvent to be commercially deployed: (a) high capital cost; (b) high thermal efficiency penalty due to solvent regeneration. Applying process intensification (PI) technology into PCC with solvent process has the potential to significantly reduce capital costs compared with conventional technology using packed columns. This paper intends to evaluate different PI technologies for their suitability in PCC process. The study shows that rotating packed bed (RPB) absorber/stripper has attracted much interest due to its high mass transfer capability. Currently experimental studies on CO₂ capture using RPB are based on standalone absorber or stripper. Therefore a schematic process flow diagram of intensified PCC process is proposed so as to motivate other researches for possible optimal design, operation and control. To intensify heat transfer in reboiler, spinning disc technology is recommended. To replace cross heat exchanger in conventional PCC (with packed column) process, printed circuit heat exchanger will be preferred. Solvent selection for conventional PCC process has been studied extensively. However, it needs more studies for solvent selection in intensified PCC process. The authors also predicted research challenges in intensified PCC process and potential new breakthrough from different aspects

Carbon capture from pulverized coal power plant (PCPP): Solvent performance comparison at an industrial scale

Coal is the most abundant fossil fuel on the planet. However, power generation from coal results in large amounts of greenhouse gas emissions. Solvent-based carbon capture is a relatively mature technology which can potentially mitigate these emissions. Although, much research has been done on this topic, single-point performance analysis of capture plant and ignoring operational characteristics of the upstream power plant may result in unrealistic performance assessments. This paper introduces a new methodology to assess the performance of CO2 capture solvents. The problem is posed as retrofitting an existing pulverized coal power plant with post-combustion carbon capture using two solvents: CDRMax, a recently developed amine-promoted buffer salt (APBS) solvent by Carbon Clean Solutions Limited (CCSL) and the monoethanolamine (MEA) baseline solvent. The features of interest include model development and validation using pilot plant data, as well as integrated design and control of the capture process. The emphasis is on design and operation of the capture plant, when integrated with the upstream coal-fired power plant, subject to variations in the electricity load. The results suggest that optimal design and operation of capture plant can significantly mitigate the energetic penalties associated with carbon capture form the flue gas, while providing effective measures for comparing solvent performances under various scenarios

Improving Prediction Accuracy of a Rate-Based Model of an MEA-Based Carbon Capture Process for Large-Scale Commercial Deployment

Carbon capture and storage (CCS) technology will play a critical role in reducing anthropogenic carbon dioxide (CO2) emission from fossil-fired power plants and other energy-intensive processes. However, the increment of energy cost caused by equipping a carbon capture process is the main barrier to its commercial deployment. To reduce the capital and operating costs of carbon capture, great efforts have been made to achieve optimal design and operation through process modeling, simulation, and optimization. Accurate models form an essential foundation for this purpose. This paper presents a study on developing a more accurate rate-based model in Aspen Plus® for the monoethanolamine (MEA)-based carbon capture process by multistage model validations. The modeling framework for this process was established first. The steady-state process model was then developed and validated at three stages, which included a thermodynamic model, physical properties calculations, and a process model at the pilot plant scale, covering a wide range of pressures, temperatures, and CO2 loadings. The calculation correlations of liquid density and interfacial area were updated by coding Fortran subroutines in Aspen Plus®. The validation results show that the correlation combination for the thermodynamic model used in this study has higher accuracy than those of three other key publications and the model prediction of the process model has a good agreement with the pilot plant experimental data. A case study was carried out for carbon capture from a 250 MWe combined cycle gas turbine (CCGT) power plant. Shorter packing height and lower specific duty were achieved using this accurate model