1,720,976 research outputs found
Process simulation and cost optimization of amine based CO2 capture integrated with a natural gas based power plant
Get PDFCombining gas-fired power plants equipped with CO2 capture systems is an efficient and cost-effective method for reducing carbon dioxide emissions from flue gases, thereby mitigating greenhouse gas emissions and combating global warming and climate change. The use of amine-based solvents for CO2 removal from exhaust gas is a well-established and effective process.
In this study, a base case scenario was modeled in Aspen HYSYS employing input data from previous studies on the integration of CO2 capture plant and NGCC (Natural Gas Combined Cycle). The base case simulation design included setting key parameters such as turbine inlet temperature (1500 °C), power generation of the combined cycle (400 MW),75 °C as the minimum temperature approach in the evaporator (ΔTmin), CO2 removal efficiency (90%), minimum temperature approach in the lean/rich heat exchanger (10 °C), and flue gas inlet temperature to the absorber (40 °C). The Enhanced Detailed Factor (EDF) and net present value (NPV) techniques as well as Aspen In-Plant Cost Estimator software, were employed to guess the total cost of the base case model, considering CAPEX, OPEX, and income from power sales. The cost evaluation revealed a net present value of €289 million over project lifetime (a 25-year), with a 16-year payback period following project implementation. Sensitivity analysis was conducted to optimize costs, using the power law method to estimate equipment costs when their sizes were changed. Parameters such as ΔTmin in lean/rich heat exchanger, and the evaporator's minimum temperature approach were adjusted to maximize the project's NPV. The other parameter was the exhaust gas recirculation (EGR) ratio. EGR is the portion of the heat recovery steam generators exhaust gas, which is recirculated back to the gas turbine inlet
The cost-optimized parameters identified from the sensitivity analysis included a zero EGR ratio, ΔTmin of 20 °C in lean/rich heat exchangers, and ΔTmin of 65 °C in evaporators. Also a python code was written to perform this automatic sensitivity calculation by calling HYSYS from Python.
The primary objective of this study was to use the Aspen HYSYS software to calculate cost and estimate cost optimum process parameters of a gas-based power plant which is integrated with an MEA-based CO2 capture system. This work is innovative in its inclusion of a sensitivity analysis on the EGR ratio and the evaporator's minimum temperature approach with this integrated model, which has not been previously addressed in similar studies
Process Simulation combined with other calculation tools for automated cost optimization of CO2 capture
Get PDFThe increasing urgency to reduce greenhouse gas emissions has placed carbon capture and storage technologies at the forefront of climate mitigation strategies. Among these, post-combustion CO2 capture using amine-based solvents such as monoethanol amine (MEA) is one of the most mature and widely studied methods. However, the high operational and capital costs associated with this process remain a major barrier to large-scale deployment.
The main objective of this project was to develop and evaluate an automated cost optimization framework for a CO2 capture process using Aspen HYSYS simulation combined with external numerical tools. Specifically, the study focused on optimizing the minimum temperature approach (ΔTmin) in the lean/rich heat exchanger and percent CO2 removal and assessing its impact on cost and energy efficiency at various CO2 removal levels.
To achieve this, a base case MEA absorption-desorption model was built in Aspen HYSYS. Python scripting was used to automate simulation runs, vary ΔTmin and CO2 removal efficiency, and extract key performance indicators including CAPEX, OPEX, and Net Present Value (NPV). The simulation incorporated Adjust and Recycle blocks to manage convergence, and different solver configurations were tested to improve result stability. Smoothing and outlier detection techniques were applied using Python for enhanced result interpretation.
The results showed that the most cost-effective performance occurred at ΔTmin values between 8-10 ⸰C for 85% CO2 removal, achieving a cost of approximately €22 per ton of CO2 captured. The lowest capture cost was calculated to be about €21 per ton of CO2 captures for 82-83 % removal.
The integration of Aspen HYSYS with Python enabled robust, repeatable simulations, reduced manual workload, and provided a flexible platform for future multi-objective optimization. This study demonstrates that such automation significantly enhances the efficiency and quality of techno-economic evaluations in carbon capture system design.
In particular, the combined use of Aspen HYSYS and Python proved highly effective for optimizing CO2 removal percentages, allowing high-resolution sensitivity analyses and supporting advanced parametric studies
Process simulation and automated cost optimization of CO2 capture
Get PDFThe growing concern over CO2 emissions has led to the development of CO2 capture technologies, with amine absorption, especially using monoethanolamine (MEA), being a widely adopted method for removing CO2 from industrial gas streams.
This study aims to advance the automation of cost optimization for CO2 capture via amine absorption, specifically using Aspen HYSYS models. The project focuses on simulating the CO2 capture process, dimensioning equipment, and automating cost estimation using the Aspen In-Plant Cost Estimator and the Enhanced Detailed Factor (EDF) method. The primary goal is to create a robust and automated process that optimizes CO2 capture costs, considering both capital expenditure (CAPEX) and operational expenditure (OPEX).
The study utilizes flue gas data from a natural gas-based power plant at Mongstad, Norway, to develop and simulate a process design in Aspen HYSYS. The base case scenario involves an absorber packing height of 15 meters, a desorber packing height of 4 meters, an 85% CO2 removal efficiency, and a minimal temperature difference (ΔTmin) of 8°C in the lean/rich amine heat exchanger. For the base case, the overall cost was calculated at 44 EUR/ton of CO2 captured, with an energy consumption of 4126 kJ/kg CO2 in the reboiler.
Several case studies were conducted to identify cost-optimal scenarios. The first case study focused on optimizing the economic performance of the lean/rich amine heat exchanger by adjusting ΔTmin from 8 to 18°C. The optimal ΔTmin was found to be around 15°C, with a CO2 capture cost of 42.5 EUR/ton and a reboiler duty of 4216 kJ/kg. This case study highlighted the trade-off between heat exchanger size and steam consumption, with automated calculations suggesting an optimal ΔTmin between 14 and 16°C.
The second case study examined the absorber packing height, varying it from 13 to 18 meters. The optimal packing height was determined to be 14 meters, resulting in a CO2 capture cost of 43.9 EUR/ton and a reboiler duty of 4036 kJ/kg CO2. This study revealed that increasing the number of absorber stages reduces the amine circulation rate and reboiler duty, influencing both capital and operational costs. It also suggested that higher CO2 concentrations in flue gas could lower costs, warranting further research into this variable.
The third case study explored the impact of varying inlet gas velocity to the absorber, ranging from 1.5 to 3 m/s. The most cost-effective velocity was found to be 2.5 m/s, with a CO2 capture cost of 53 EUR/ton and a minimum reboiler duty of 4183 kJ/kg CO2. Higher velocities initially reduced costs by enhancing CO2 absorption efficiency, but beyond 2.5 m/s, costs increased due to decreased contact time between the flue gas and amine solvent
Process Simulation, Dimensioning and Automated Cost Optimization of CO2 Capture
No full textThe use of an amine solvent to remove CO2 from the exhaust gas is an established and well-studied technology. Available emission data from prior research on a natural gas-based power plant project at Mongstad, Norway, was used to model a typical CO2 capture process in Aspen HYSYS. To undertake cost optimization, a Base Case was created with 15 m absorber packing height, 10 m desorber packing height, the removal efficiency of 85 %, and a minimum temperature approach (ΔTmin) in the lean/rich amine heat exchanger of 10 °C. To estimate and quantify the total cost for the basic scenario, the Enhanced Detailed Factor (EDF) was employed in combination with the Aspen In-Plant Cost estimator. The Base Case results showed a total cost of 42.9 EUR per ton of CO2 removed and the reboiler energy use of 3750 kJ/kg.
In the sensitivity analysis, the absorber packing height, the minimum temperature approach (ΔTmin), and the entering flue gas temperature into the absorber column were all altered to find out how different factors affected pricing variations. When the sensitivity analysis changed the size, the Power-Law approach was applied to vary the equipment cost. Using the Adjust and Recycle blocks, as well as switching the calculated values between the simulation and spreadsheets, makes the analysis more automated.
When the ΔTmin was changed from 5 °C to 20 °C, in both automatic and manual scenarios, the variation in predicted cost from 11 °C to 15 °C was minimal.
Since changing the number of stages in an automated assessment is not possible, the stage’s efficiency was changed from 0.15 to 0.9, which is equivalent to increasing the number of steps from 13 to 18. The optimum calculated packing height was 15 m, with a CO2 collection cost of 42.6 EUR/t in the manual analysis. The automated calculated costs were on average 1.5 % and 0.9 % higher than the manual technique when the target stages for changing efficiency were the 13th stage, and the 10th stage, respectively.
A 15-stage absorber was employed to automatically assess the change in incoming flue gas temperature to the absorber from 30 to 50 degrees Celsius in 5 °C steps. The computed captured cost was around 2% lower than the Base Case research due to employing lower amine flow rate by enhancing average stages’ efficiency. Similar research for a simulated case with a 13-stage absorber resulted in a cost reduction of more than 4% compared to the Base Case. When the step size was lowered to 1 °C, the best input temperature was determined to be 34 °C, with an estimated cost of 39.6 EUR per ton of CO2 captured.
The major goal was to use the Aspen HYSYS software to automatically calculate and optimize the cost of an MEA-based CO2 capture facility. This study states automated optimization of absorber packing height and gas inlet temperature using the Case Study tool in Aspen HYSYS, which has not been done before
Going Beyond Counting First Authors in Author Co-citation Analysis
Get PDFThe present study examines one of the fundamental aspects of author co-citation analysis (ACA) - the way co-citation
counts are defined. Co-citation counting provides the data on which all subsequent statistical analyses and mappings
are based, and we compare ACA results based on two different types of co-citation counting - the traditional type that
only counts the first one among a cited work's authors on the one hand and a non-traditional type that takes into
account the first 5 authors of a cited work on the other hand. Results indicate that the picture produced through this non-traditional author co-citation counting contains more coherent author groups and is therefore considerably clearer. However, this picture represents fewer specialties in the research field being studied than that produced through the traditional first-author co-citation counting when the same number of top-ranked authors is selected and analyzed. Reasons for these effects are discussed
Cost estimation methods for CO2 capture processes
No full textCost engineering and economic assessment play a crucial role in evaluation of CO2 capture technologies and energy systems. Cost is one of the key decisive factors when considering industrial deployment of a technology. Economic analysis is very important when a selection is to be made from different options. Estimates of CO2 capture and storage processes are essential for making policies, and for making important decisions like funding of research and projects, as well as investment in industrial implementations.
Capital cost estimates made by engineering and procurement contractors (EPC) are usually accurate. Nevertheless, their methodologies are usually not open and transparent for others to adopt due to commercial policies. The technical and economic underlying assumptions utilised are normally not disclosed. They are also difficult and expensive to access by researchers, students and others that are not in the commercial and governmental sectors. The common practice for capital cost estimation in the open literature is that a single overall installation factor is applied uniformly on all equipment. The results from this study propose that it may likely lead to over-estimation of very expensive equipment and under-estimation of least expensive equipment. At best, it limits such methods suitability to only cost estimation of new and large plants.
It has been stated in literature that the accuracy of capital cost estimates can be improved by applying detailed factors and sub-factors as provided by the Enhanced Detailed Factor (EDF) method. The EDF method is robust, especially with the introduction of the plant construction characteristic factors (PCCF). They account for different situations that may be encountered in different plant construction projects. In the EDF method, installation factors are assigned to each piece of equipment based on their costs. A very expensive equipment unit is assigned a lower installation factor while a less expensive equipment unit will have a high installation factor. Therefore, the EDF method is suitable and robust for capital cost estimation of new plants, modification projects and retrofit plants, and large and small plants.
The EDF method’s installation factors are more sensitive to differences in equipment costs compared to the Lang Factor method, Hand Factor method, percentage of delivered equipment (PDE) cost and the Bare Erected Cost (BEC) method. All the seven methods studied in this project estimated the same cost optimum minimum temperature approach (∆) based on CO2 capture cost. Nevertheless, the capture costs were different, ranging from €66/tCO2 to €79/tCO2. The total plant cost estimates of the BEC method, the Lang Factor method, and the percentage of delivered equipment cost method which are purely based on application of a single installation factor uniformly on all equipment were 31 – 54 % higher than the result of the EDF method.
Due to the details involved in the EDF method, it is relatively time intensive, and it requires more work to implement. This becomes challenging when there is a need for several iterative calculations. For example, iterative cost estimation with each iteration involving process simulations, equipment dimensioning, capital cost, operating cost and other economic analysis. This is the case for sensitivity analysis and cost optimisation studies which are very important in techno-economic analysis. Therefore, the Iterative Detailed Factor (IDF) scheme was proposed as a simple tool for cost estimation and optimisation tool for fast and accurate cost estimation based on the EDF method. The IDF scheme was implemented by means of the spreadsheets incorporated in Aspen HYSYS. The models for equipment dimensioning, capital cost and operating cost, as well as other key performance indicators were created inside the Aspen HYSYS spreadsheets. It is based on estimating new equipment costs using the Power Law when subsequent simulations iterations are performed after the initial one. When a process parameter is varied, immediately after the simulation has converged, all cost estimates can be automatically obtained. For the columns, a cost exponent of 1.1 for new sizes above the original size and 0.85 below the initial size achieved the most accurate estimates in this study. A cost exponent of 0.65 was utilised for estimation of the costs of all equipment that is affected by the change in the process parameter. Other equipment not affected was assigned a cost exponent of 1. The error with the IDF scheme was 0 – 0.4 % in estimation of total plant cost compared to the EDF method.
Different specific types of heat exchangers for CO2 absorption plant were studied. This was to evaluate their cost reduction and emissions reduction potentials. They are the fixed tubesheet shell and tube heat exchanger, floating head shell and tube heat exchanger, U-tube shell and tube heat exchanger, gasketed plate heat exchanger and welded plate heat exchanger. The gasketed plate heat exchanger outperformed all the other heat exchanger types in capital cost, CO2 capture cost, CO2 avoided cost and CO2 actual emissions reduction. Their limitations are not very important in a solvent based CO2 capture system. This project recommends the use of plate heat exchangers for the cross-heat exchanger with a minimum temperature approach of 4 – 7 ℃. It is also recommended for the lean amine cooler and for the direct contact unit water cooler in a CO2 absorption and desorption process.
Cost estimation and optimisation were performed for a standard monoethanolamine based process and for several other alternative processes. For example, the EDF method based on the IDF scheme was also applied to study a combined rich and lean vapour compression configuration for CO2 capture. The combined configuration achieved the best energy and economic performance compared to the simple rich vapour compression and the simple and lean vapour compression configurations.
The EDF method was mainly implemented in the IDF Scheme (automatic) approach in this PhD study and in master students’ projects as well as master’s theses. Most of the studies focused on automatization of cost estimation and process parameters cost optimisation. The studies demonstrated that the EDF method implemented in the IDF scheme approach is fast and robust to optimize process parameters like minimum temperature approach of the lean/rich heat exchanger, columns packing heights and others. Therefore, this work recommends the EDF/IDF method for cost estimation of CO2 absorption processes and process parameters optimisation
Variations on the Author
Get PDF“Variations on the Author” discusses two of Eduardo Coutinho’s recent films (Um Dia na Vida, from 2010, and Últimas Conversas, posthumously released in 2015) and their contribution to the general question of documentary authorship. The director’s filmography is characterized by a consistent yet self-effacing form of authorial self-inscription: Coutinho often features as an interviewer that rather than express opinions propels discourses; an interviewer that is good at listening. This mode of self-inscription characterizes him as an author who is not expressive but who is nonetheless markedly present on the screen. In Um Dia na Vida, however, Coutinho is completely absent form the image, while Últimas Conversas, on the contrary, includes a confessional prologue that moves the director from the margins to the center of his films. This article examines the ways in which these works stand out in the filmography of a director who offers new insights into the notion of cinematic authorship
New Concept for Evaluating the Risk of Hydrate Formation during Processing and Transport of Hydrocarbons
Get PDFTransport of hydrocarbons from reservoir to gas processing plants and for supply to delivery terminals is predominantly done using pipelines, particularly within reasonable distance. In the North Sea of Norway, there are about 8000 km network of pipelines transporting hydrocarbons. Transport and processing operations of hydrocarbons in the North Sea are typically at elevated pressures. The seafloor temperatures are normally low; because of the seawater salinity it could be as low as 272.15 K in the northern part, and seldom rise above 279.15 K in the south. If liquid water condenses out of hydrocarbon gas streams at these conditions of high pressures and low temperatures, with favourable mass and heat transport, nucleation and growth of natural gas hydrate is expected to occur. The typical technique the industry currently apply to examine the risk of hydrate formation is based on estimation of water dew-point for the gas in question. And if any condition of temperature and pressure in the pipeline or processing equipment is above water dew-point so that water condenses out, then the amount of water that will drop out is evaluated. This is followed by hydrate formation evaluation, including maximum amount of hydrate that can be expected to form from the condensed water. Prevention of hydrate formation with this classical approach known as dew-point method therefore involves estimating the maximum amount of water that can be permitted in the hydrocarbon gas without the risk of liquid water dropping out and eventually leads to hydrate formation. The shortcoming of the classical scheme is that it totally disregards another (a new) concept which involves water dropping out of the bulk through the mechanism of adsorption on rusty surfaces. Pipelines and some equipment are generally rusty even before they are mounted together and put in place. Rust is a mixture of iron oxide and in this study refers to Hematite (Fe2O3) which is one of the most thermodynamically stable forms of rust. These rusty surfaces provide water adsorption sites that can also lead to hydrate formation. However, hydrate formation cannot occur directly on the surfaces covered by Hematite. This is because the distribution of partial charges of hydrogen and oxygen in the lattice are incompatible with the atom charges in the rusty (Hematite) surfaces. But the rusty surfaces act as catalyst that help to take out the water from the gas stream via the process of adsorption, and hydrate formation can follow slightly outside of the first two or three water layers of about one nanometre. In this project, real hydrocarbon mixtures are studied for the first time using a novel thermodynamic scheme, with composition data which is openly available for the Troll gas and Sleipner gas from the North Sea. The model has been comprehensively validated in this work for pure and mixtures of hydrocarbons, CO2, H2S, and hydrocarbon mixtures with these inorganic gases with experimental data from 35 established literature. Estimates of maximum concentration of water tolerable in hydrocarbon gas systems containing structure I and structure II guest molecules during processing and pipeline transport with the classical dewpoint technique is in order of 18-21 times higher than the estimates with the new concept of evaluating the risk of hydrate formation based on water dropping out by the process of adsorption on Hematite. This alternative route to hydrate formation through adsorption of water on hematite absolutely dominates in evaluating the risk of water dropping out from the gas mixtures (and pure components investigated) to form a separate water phase and eventually lead to hydrate formation. This reason is because the average chemical potential of the water adsorbed on Hematite is approximately 3.4 kJ/mol less than the chemical potential of liquid water. And thermodynamics favours minimum free energy. The typical trend exhibited by methane, methane-dominated gas mixtures like Troll gas and Sleipner gas, and carbon dioxide is decline in the upper limit of water with increasing pressure. The heavier hydrocarbon (ethane, propane, and isobutane) gases exhibits opposite trend to that of CH4 and CH4-dominated gas mixtures where the permitted maximum water content increases with increase in pressure. This manifestation is due to the high density nonpolar phase at the high pressures of the C2+. The non-polar heavier hydrocarbons (especially of structure II hydrate formers) will act to draw down the maximum concentration of water that can be permitted in the gas mixture to a point where they completely dominate or dictate the trends. This is why the safe-limit of water tolerable in Sleipner gas is lower than that of Troll gas which contains lesser amount of C2+. The safe-limit of water to prevent the risk of hydrate formation during processing and pipeline transport of CO2 is only very slightly less than that CH4. Higher concentrations of H2S up to 5% and above would have a significant impact of reducing the maximum concentration of water that can be permitted in hydrocarbon gas mixtures during processing and pipeline transport operations
Appropriate Similarity Measures for Author Cocitation Analysis
Get PDFWe provide a number of new insights into the methodological discussion about author cocitation analysis. We first argue that the use of the Pearson correlation for measuring the similarity between authors’ cocitation profiles is not very satisfactory. We then discuss what kind of similarity measures may be used as an alternative to the Pearson correlation. We consider three similarity measures in particular. One is the well-known cosine. The other two similarity measures have not been used before in the bibliometric literature. Finally, we show by means of an example that our findings have a high practical relevance.information science;Pearson correlation;cosine;similarity measure;author cocitation analysis
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