Post-combustion CO2 Capture Unit Research Articles

Design and thermo-enviro-economic analyses of an innovative environmentally friendly trigeneration process fueled by biomass feedstock integrated with a post-combustion CO2 capture unit

The utilization of biomass feedstock in the energy system for sustainable production is essential due to its renewable nature and high energy density. However, the primary challenge lies in designing environmentally friendly biomass-use structures. This research introduces a novel trigeneration system that integrates power, cooling, and heat production through biomass combustion to address this issue. As another novelty in system development, the proposed system includes a carbon dioxide capture unit, further enhancing the system. The proposed framework consists of several subsystems: an organic Rankine cycle, an absorption chiller, a carbon dioxide capture cycle utilizing monoethanolamine solvent, a liquefied natural gas regasification unit, and a low-pressure steam production boiler. The newly developed system is modeled using the Aspen HYSYS software and is assessed from thermodynamic, economic, and environmental perspectives. Also, a parametric analysis is conducted to examine the impact of key design parameters on the system’s performance. Based on the study’s findings, it can be observed that the energy and exergy efficiencies amount to 58.4 % and 17.09 %, respectively. In addition, the suggested procedure exhibits a total exergy destruction of 53,636 kW. The findings of the environmental impact assessment indicate that the shift from power generation to trigeneration scenario results in a substantial decrease in carbon dioxide emissions. Specifically, the emission reduction potential ranges from 0.24 to 0.041 kg/kWh. Furthermore, the economic evaluation shows that the system reaches a cost per unit exergy of 0.249 $/kWh. This variable denotes a substantial decrease of 81.42 % compared to the power generation operational mode.

Exergy analysis of modified-supercritical power plant with solar assisted feedwater heating and CO<SUB align="right">2 capture

Solar energy is the most readily available energy in India, which can be utilised in coal-fired thermal power plants for feedwater heating and Monoethanolamine (MEA) for MEA regeneration in post-combustion CO2 capture unit. The present study deals with 4-E (energy, exergy, environment, and economic) analysis of a 500 MWe Supercritical (SupC) coal-based thermal power plant with solar-assisted feedwater heating and MEA regeneration in CO2 capture unit. Results show that the plant efficiency is improved by 8.2% points, and the coal consumption rate is reduced by 18%. The levelised cost of electricity (LCoE) generation is increased to INR 6, and the cost for CO2 avoided is INR 3607 per tonne of CO2.

Life cycle cost and environmental assessment of CO2 utilization in the beverage industry: A natural gas-fired power plant equipped with post-combustion CO2 capture

Besat is a natural gas-fired steam-turbine power plant in Tehran, Iran’s only power station equipped with a monoethanolamine-based post-combustion CO2 capture unit (PCCU). The PCCU operates at a low recovery rate of 4.7% and produces 58 t-CO2/day. Captured CO2 is encapsulated and sold to beverage companies for carbonated soft drink production. Before developing this CO2 capture and utilization (CCU) route, a beverage company like ZamZam produced CO2 on-site, capturing CO2 from flue gas of diesel-fired boilers using a 95%-efficient absorption-refrigeration unit. This paper conducts an attributional, comparative life-cycle assessment/costing of applying the CCU technology to supply the beverage industry with CO2. ReCiPe, cumulative energy demand, and AWARE impact assessment methods are adopted to assess changes in the life-cycle economic, energy, and environmental impacts of electricity, liquid CO2, and carbonated water supply chains with the CCU route. As per findings, the CCU route significantly improves the sustainability profile of liquid CO2 supply for carbonated water production. Compared to on-site production, the CCU route reduces the average economic, energy, and environmental impacts of liquid CO2 supply by 55, 44, and 62%, respectively. However, the figures for carbonated-water production are reduced by only 10.1, 0.85, and 0.77%, respectively, since associated impacts primarily result from citric acid and polyethylene terephthalate value chains rather than liquid CO2. The CCU route, in comparison, increases most environmental burdens of electricity generation. With an efficiency of 4.7%, the PCCU reduces the global warming potential of electricity generation by 6.22% while increasing average toxicity- and eutrophication-related impacts by 55 and 30%, respectively, and production costs by 8%.

Comments on “Elucidating the important thermo physical characterization properties of amine activated hybrid novel solvents for designing post-combustion CO2 capture unit”

• Published excess molar volumes are inconsistent with the experimental density data. • Reanalysis of the measured data for select blends indicates that V E should be negative and not positive as initially reported. • Guidelines are provided for quickly checking for obvious errors in calculated V E values. A polemic is provided regarding the volumetric properties reported in the published paper by Balchandani and coworkers. The published excess molar volumes of binary and ternary aqueous blends of amine activated hybrid novel solvents depicted in Figure 2 of the published paper and listed in Table S10 of the accompanying Supporting Information are not consistent with the measured density. The authors reported positive numerical values for the excess molar volumes, however, a reanalysis of the experiment data for select mixtures reveals that the excess molar volumes are negative.

Elucidating the important thermo physical characterization properties of amine activated hybrid novel solvents for designing post-combustion CO2 capture unit

The surge in energy demand globally has resulted in high level of CO2 emissions through large industrial point sources. Chemical or physical absorption is one of the widely used methods utilized for large scale CO2 capture. The utility of any solvent in CO2 absorption system requires the detail fundamental understanding of physicochemical properties associated with the solvent. In the present work, physicochemical properties of six different aqueous blends of hybrid solvents of (3-aminopropyl) triethoxysilane (TESA), N-methyldiethanolamine (MDEA), sulfolane (TMSO2), 1-butyl-3-methyl-imidazolium acetate ([bmim][Ac]) activated by 1-(2-aminoethyl) piperazine (AEP), bis-(3-aminopropyl)amine (APA) and 2-methyl piperazine (2-MPZ) are studied. Various important physiochemical properties needed for process design viz. density, viscosity, surface tension, refractive index and sound velocity are measured over a broad range of temperature (298.15–333.15) K and concentration. Redlich-Kister and Grunberg-Nissan models have been used for correlating density and viscosity. Statistical regression have been applied for correlating sound velocity, refractive index and surface tension. Important derived properties of the proposed solvents have been also evaluated through empirical correlations.

Prediction of CO2 solubility in potential blends of ionic liquids with Alkanolamines using statistical non-rigorous and ANN based modeling: A comprehensive simulation study for post combustion CO2 capture

Equilibrium CO2 solubility data plays a pivotal role in the process design of the post-combustion CO2 capture Unit. In the current study, statistical non-rigorous models are developed to predict the solubility of carbon dioxide (CO2) in different aqueous blends of ionic liquids (ILs) and blends of ILs with alkanolamines, ethanol, etc. These correlations are utilized to estimate the liquid phase CO2 loading as a function of CO2 partial pressure at different temperature conditions. The correlations can predict CO2 solubility in the liquid phase of different (ILs + alkanolamine + water/ethanol) in the temperature and CO2 partial pressure range of (298–353) K and (50–6200) kPa respectively. The CO2 mole fraction in the liquid phase pertaining to 19 different solvent formulations is considered in the range of (0–0.487). It has been found that there is a good agreement between the results of the proposed models and reported experimental data of CO2 solubility. In addition to this, the predictability of artificial neural network (ANN) for CO2 solubility is also tested for 22 systems of ionic liquid blends with amines. The main advantages associated with these proposed models are their underlying simplicity and minimal input data, namely temperature and pressure.

A natural gas-based eco-friendly polygeneration system including gas turbine, sorption-enhanced steam methane reforming, absorption chiller and flue gas CO2 capture unit

Poly-generation systems have attracted a lot of attention due to the increment of efficiency as well as reducing energy penalties, costs and pollutants. Extensive research has been done on these systems in recent years. The current work is done with the aim of simulating an environmentally friendly poly-generation system in the power plant of Shahrood city in Iran. In this way, a poly-generation system is simulated in Aspen Plus software which consists of: I) a gas turbine (GT) for power generation with natural gas fuel of Shahroud power plant, that its flue gas is utilized to supply heat for other cycles and streams, II) a sorption-enhanced chemical looping reforming (SECLR) which simultaneously generates H2 by steam methane reforming (SMR) and uptakes produced CO2 by calcium adsorbent during the carbonation/calcination reactions. In this section, there is also a chemical looping combustion (CLC) based on redox reactions of Ni/NiO to provide heat of the reactors, III) a NH3/H2O absorption refrigeration system to yield the cooling demand, IV) a high-pressure steam generation unit and V) a MEA-based post-combustion CO2 capture unit (PCC) for flue gas. In this system, an attempt has been made to prevent heat loss by internal streams, especially gas turbine exhaust gas, so that energy loss is minimized. Moreover, environmental issues are also prioritized to reduce the CO2 emissions as much as possible. The proposed process is capable of producing 133.3 MW power, 9.875 MW cooling, 50 kg/s high-pressure steam and 0.384 kg/s hydrogen. The mass flow rates of CO2 captured in the SECLR and PCC sections are 2.6 kg/s and 15.35 kg/s, respectively. Moreover, the total energy efficiency of the integrated system is 68.74%. Ultimately, a sensitivity analysis was performed to identify the key parameters and their influence on the process performance.

Pilot scale testing of an advanced solvent in a 0.7 MWe post-combustion CO2 capture unit

An advanced Amine Promoted Buffer Solution (APBS), APBS-CDRMax® (CDRMax), developed by Carbon Clean Solutions Limited (CCSL), was tested at the 0.7 MWe CO2 capture facility at Kentucky Utilities E.W. Brown Generation Station using a heat-integrated two-staged stripping CO2 capture process. The performance of the solvent was evaluated to determine operating conditions that maximized the cyclic capacity of the solvent and results in energy savings. The regeneration energy ranged from 2.9 to 3.3 GJ/ton CO2 with 14 vol % (dry) CO2 inlet and approximately 90 % capture. The difference in the reboiler specific heat duty at stripper pressures of 1.7 and 2.1 bar was minimal as similar amounts of water vapor were observed in the CO2 product stream at stripper outlet. Recycling of product CO2 increased the inlet CO2 concentration to the absorber from 14 to 16 vol% which enhanced mass transfer from the gas to the solvent resulting in about 5 % reduction in the energy of regeneration at the lower stripper pressure. The solvent circulation rate was reduced by about 30 % relative to previous 30 wt% MEA campaign for the CO2 target capture of 90 %. Additionally, the reduced solvent make-up rate of CDRMax shows promise for capital and operating cost savings for post-combustion CO2 capture.

Thermoeconomic analysis and optimization of post‐combustion CO2 recovery unit utilizing absorption refrigeration system for a natural‐gas‐fired power plant

Exergy and exergoeconomic analyses have been used to set out weaknesses of the postcombustion CO2 capture unit of Besat power plant that uses an ammonia absorption refrigeration system for CO2 liquefaction. The energy required for the absorption system is provided by the flue gas. The liquefied CO2 is used for beverage and food industries. The exergoeconomic costs of all utility streams and processes are calculated through a systematic method of assigning exergetic cost relations to the streams. The results point out that the exergy destruction of the CO2 stripper and absorber columns are the highest, and according to the cost‐based information, potential locations for the process improvement are proposed. A comprehensive method based on thermodynamic and mathematical methods has been proposed to acquire efficient design parameters and consumed power in compressors. It is based on a combination of Aspen HYSYS® and MATLAB® to do calculations and then an optimization procedure based on genetic algorithms. Results show that the production cost of each ton CO2 is equal to 6.05 (USD/ton) and return on investment can also be obtained by 2.5 years considering USD 1,600,000 of annual revenue. © 2018 American Institute of Chemical Engineers Environ Prog, 37: 1075–1084, 2018

CO2 Capture from Sulphur Recovery Unit Tail Gas by Shell Cansolv Technology

A significant driver for the climate change effect is CO2 emission from the sources where fossil fuel is consumed to generate energy. Capturing and sequestration of CO2 from these emission sources is a practical way to mitigate GHG emission impact. However the cost of CCS projects has been a major obstacle to implementing these technologies worldwide. Two main aspects which influence the cost of a CO2 capture project are the CO2 utilization pathway and the CO2 capture technology selection.CO2-Enhanced Oil Recovery (EOR) can be a very good potential pathway to increase the revenue of the CCS project. CO2-EOR also can be an attractive way of using CO2 in areas such as Middle East where the oil and gas reservoirs are mature. However one of the main constraints can be limited access to CO2 especially where no power plant is close to a potential oil reservoir.For technology selection, the choice is typically between Pre- and Post-Combustion. Pre-combustion CO2 capture technologies have been deployed in oil refineries & gas processing plants for decades, but the main source for CO2 emissions in these facilities is often off-gas (also known as acid gas) which is usually sent to the flare system or incinerator. These off-gases are at low pressure, so a compression system is required to pressurize the gas before sending it to the Pre-combustion CO2 capture unit. On the other hand, Post-combustion CO2 capture technology can often require an additional desulfurization step to remove SO2 which can potentially result to higher operational and capital cost as well as waste management and complexity of operation. This paper will discuss the deployment of Shell Cansolv technology to capture CO2 from off-gas downstream of the Sulfur Recovery Unit (SRU) in a single train, potentially as a new CCS application in the oil and gas sectors.The off-gas from Tail Gas Treatment Unit (TGTU) downstream of the SRU will usually contain a higher amount of CO2 compared to coal and gas power plants. The absorption affinity of Shell Cansolv solvent at low pressure off-gas compared to other pre-combustion technologies allows the elimination of the primary compression system located upstream of the CO2 capture unit. Since there is H2S slippage from the TGTU absorber overhead, the amine should be characterized in terms of absorption affinity and stability in the reduced environment. The impact of H2S on amine performance in terms of degradation has been investigated in comparison to a post-combustion application where H2S is incinerated and converted to SOx. SOx contaminates amine to form Heat Stable Salt (HSS), so it needs to be removed prior to the post-combustion CO2 capture unit in a separate FGD unit (Flue Gas Desulfurization). Shell Cansolv DC amine in pre-combustion lineup absorbs both H2S and CO2 in a single absorber so incinerator and FGD unit is not required compared to post-combustion applications. Shell Cansolv DC amine has been tested to remove up to 99% CO2 which is higher than the 90% typical capture rate for most post-combustion applications. The other advantage of this application is the ability to operate at high temperature (∼60 C). This is often a key design parameter especially in the Middle East where most applications are considered hot climate applications. All design parameters of the CO2 capture unit such as liquid per gas ratio (L/G), stripping factor at the regenerator side and absorber packing height have been evaluated and optimized to reduce both capital and operational costs of the project. Eventually, in a case study, an economic comparison was conducted and the result indicated potentially more than 40% reduction in the cost of a CO2 capture unit as well as same magnitude increase in Net Present Value (NPV) compared to pre-combustion technology.

Demonstrating load-change transient performance of a commercial-scale natural gas combined cycle power plant with post-combustion CO2 capture

The present work aims to study the transient performance of a commercial-scale natural gas combined cycle (NGCC) power plant with post-combustion CO2 capture (PCC) system via linked dynamic process simulation models. The simulations represent real-like operation of the integrated plant during load change transient events with closed-loop controllers. The focus of the study was the dynamic interaction between the power plant and the PCC unit, and the performance evaluation of decentralized control structures. A 613MW three-pressure reheat NGCC with PCC using aqueous MEA was designed, including PCC process scale-up. Detailed dynamic process models of the power plant and the post-combustion unit were developed, and their validity was deemed sufficient for the purpose of application.Dynamic simulations of three gas turbine load-change ramp rates (2%/min, 5%/min and 10%/min) showed that the total stabilization times of the power plant’s main process variables are shorter (10–30min) than for the PCC unit (1–4h). A dynamic interaction between the NGCC and the PCC unit is found in the steam extraction to feed the reboiler duty of the PCC unit. The transient performance of five decentralized PCC plant control structures under load change was analyzed. When controlling the CO2 capture rate, the power plant performs in a more efficient manner at steady-state part load; however, the PCC unit experiences longer stabilization times of the main process variables during load changes, compared with control structures without CO2 capture rate being controlled. Control of L/G ratio of the absorber columns leads to similar part load steady-state performance and significantly faster stabilization times of the power plant and PCC unit’s main process variables. It is concluded that adding the PCC unit to the NGCC does not significantly affect the practical load-following capability of the integrated plant in a day-ahead power market, but selection of a suitable control structure is required for efficient operation of the process under steady-state and transient conditions.

Benchmarking of a micro gas turbine model integrated with post-combustion CO2 capture

The deployment of post-combustion CO2 capture on large-scale gas-fired power plants is currently progressing, hence the integration of the power and capture plants requires a good understanding of operational requirements and limitations to support this effort. This article aims to assist research in this area, by studying a micro gas turbine (MGT) integrated with an amine-based post-combustion CO2 capture unit. Both processes were simulated using two different software tools –IPSEpro and Aspen Hysys, and validated against experimental tests. The two MGT models were benchmarked at the nominal condition, and then extended to part-loads (50 and 80 kWe), prior to their integration with the capture plant at flue gas CO2 concentrations between 5 and 10 mol%. Further, the performance of the MGT and capture plant when gas turbine exhaust gases were recirculated was assessed. Exhaust gas recirculation increases the CO2 concentration, and reduces the exhaust gas flowrate and specific reboiler duty. The benchmarking of the two models revealed that the IPSEpro model can be easily adapted to new MGT cycle modifications since turbine temperatures and rotational speeds respond to reaching temperature limits; whilst a detailed rate-based approach for the capture plant in Hysys resulted in closely aligned simulation results with experimental data.

Optimal Design of Solvent Based Post Combustion CO2 Capture Processes in Quicklime Plants

cCaO-Hellas S.A., 6 th km Langada-Thessalonikis Rd., 57013,Thessaloniki, Greece seferlis@cperi.certh.gr The optimal design of a solvent based post combustion CO2 capture unit in a quicklime production plant is investigated. A 30 % weight aqueous monoethanolamine (MEA) solution is used as the absorption agent for the treatment of a 14 % mol CO2 flue gas stream. The objective function in the design optimization incorporates several equipment capacity and operating factors that have a direct impact on capital expenditure and energetic cost of the unit. A reliable and accurate equilibrium model is developed for the prediction of the process behavior. The model employs an orthogonal collocation on finite element formulation enabling structural flexibility for design purposes and efficient model reduction for computational facilitation. Nonlinear programming techniques are used for the identification of the optimal column configuration and the operating conditions. The ability of the optimally designed absorption/desorption column to achieve acceptable performance under varying separation operating conditions such as flue gas CO2 concentration, flowrate, and temperature is investigated. European policies on greenhouse gas (GHG) emissions reduction have already been adopted in order to meet the ambitious but necessary targets set for climate change prevention. Satisfaction of such targets will not only affect the global economy and specifically the energy intensive industrial sector, but also secure the competitiveness of industry in a constantly demanding market. Amongst the industrial contributors in GHG emissions, the cement and quicklime industry are significant contributors to the overall amount of released CO2. In 2008 alone, 38.5 % of the total European industrial CO2 emissions came from the cement industry, a percentage corresponding to 3.2 % of the total CO2 emitted (European Commission DG JRC, 2010). Especially in the case of the cement plants, up to 60 % of the emitted CO2 is derived from the calcination of limestone (Bosoaga et al., 2009). It is therefore evident that emissions control during the production of quicklime through the calcination step is a major contribution towards the overall reduction of CO2.

The Effect of Advanced Steam Parameter-Based Coal-Fired Power Plants With Co2 Capture on the Indian Energy Scenario

This study deals with the performance analysis of 500 MWe pulverized coal-fired power plants based on subcritical (SubC), supercritical (SupC), and ultrasupercritical (USC) steam parameters with postcombustion CO2 capture using high ash (HA) Indian coal. The performance of power plants is evaluated in terms of plant energy efficiency and CO2 avoided. Furthermore, the effect of an imported low ash (LA) coal on power plant performance parameters is also determined compared with the HA Indian coal. SupC and USC power plants result in an increase of about 0.8% and 6.4% points, respectively, in the plant energy efficiency compared with the SubC power plant. Consequently, a reduction of about 3% and 16.5% in CO2 emission is observed for the same plants using both HA and LA coals that, in turn, will aid in significant gain in carbon credits for a developing country such as India. However, incorporation of postcombustion CO2 capture unit in the proposed power plant configurations result in a significant drop of about 8%--13% points in the plant energy efficiency.

Health risk analysis for emissions to air from CO2 Technology Centre Mongstad

A health risk analysis for the emissions to air from the CO2 Technology Centre Mongstad (TCM) has been executed. TCM is the world's largest facility for testing and improving technologies for CO2 capture, and is located at the West coast of Norway. The risk analysis was an important fundament for the application for an emission permit for the amine based post-combustion CO2 capture unit. The highest risk was assessed to be the exposure of the population to uncertain concentrations of nitrosamines and nitramines in air and drinking water. Nitrosamines and nitramines are groups of possible degradation products formed from amines. The components within these two groups have variable degrees of carcinogenicity. Nitrosamines are formed from amines in the CO2 capture process and in the atmosphere, while nitramines are assumed to form only in the atmosphere. The risk was analyzed by comparing the sum of concentrations of nitrosamines and nitramines in air and fresh water with recently available guidelines. The concentrations were obtained by modelling atmospheric chemistry, dispersion, deposition by precipitation and degradation in fresh water with novel methods that were developed during the application process. Moreover, the nitrosamine and nitramine concentrations were measured in air and fresh water lakes prior to start-up as a baseline. TCM's conclusion was that the risk was acceptable. The Norwegian Climate and Pollution Agency granted TCM a permit in November 2011.

Development of a Dynamic Model of a Post Combustion CO2 Capture Process

Carbon capture and storage (CCS) is a potential means of mitigating the contribution of the green house gas emissions from the fossil fuel usage to the global warming. Post combustion CO2 capture via amine absorption is one of the most matured techniques to comprehend the goals of CCS. A Dynamic model of an amine based post combustion capture plant including the absorption and stripping towers is developed in order to contribute in the journey from the lab scale towards the industrial scale capture plants. The dynamic model is validated against the literature data. The capability of the model to predict the dynamics of a post combustion CO2 capture unit is analyzed via a possible scenario of a real plant.

Design-point and part-load considerations for natural gas combined cycle plants with post combustion capture

An investigation is made of two different integration options for a MEA post-combustion CO2 capture unit in a natural gas combined cycle (NGCC). Thereafter, a study is made of the part load operation of the NGCC with and without CO2 capture.The considered integration options were (1) steam extraction from LP superheater and at IP–LP crossover as heat source to the stripper reboiler and (2) partially integrating the reboiler directly into the HRSG while extracting steam at the IP–LP crossover for the remaining heat duty. The results show that both options exhibit similar operational performance at full and part-load. However, the process option with direct integration of 40% of the reboiler into the HRSG results in only one steam pressure level in the HRSG and the heat transfer area can be reduced with 38%.Additionally, the paper presents a qualitative discussion on the steam supply from the power plant to the CO2 capture unit under transient conditions. This is done with reference to the steady-state part-load results. An overall conclusion is that the NGCC will always be able to supply the capture unit with sufficient steam for solvent regeneration at full load, part load and during load changes. The ability to maintain a capture rate at 90% will depend on the operational performance of the capture plant.

Capture-ready supercritical coal-fired power plants and flexible post-combustion CO2 capture

Abstract Delivering a rapid reduction in global CO2 emissions through CCS requires a two-track approach: CCS needs to be developed at s cale as quickly as possible and other plants, if built without CCS, need to be built CO2 capture ready (CCR). CCR plants can be upgraded as CCS technology develops so that their cost of electricity production can be minimised. Retrofitted CCR plants could also be very suitable for providing flexible electricity output. The options availabl e for making steam turbines at pulverised coal plants suitable for adding post-combustion CO2 capture unit s are discussed, together with their potential for upgrad ing and enhanced flexibility.