Natural Gas-fired Power Plants Research Articles

The Impact of Retrofitting Natural Gas-Fired Power Plants on Carbon Footprint: Converting from Open-Cycle Gas Turbine to Combined-Cycle Gas Turbine

Since retrofitting existing natural gas-fired (NGF) power plants is an essential strategy for enhancing their efficiency and controlling greenhouse gas emissions, this paper compares the carbon footprint of natural gas-fired power generation from an NGF power plant in Brazil (BR-NGF) with and without retrofitting. The former scenario entails retrofitting the BR-NGF power plant with combined-cycle gas turbine (CCGT) technology. In contrast, the latter involves continuing the BR-NGF power plant operation with open-cycle gas turbine (OCGT) technology. Our analysis considers the BR-NGF power plant’s life cycle (construction, operation, and decommissioning) and the natural gas’ life cycle (natural gas extraction and processing, liquefaction, liquefied natural gas transportation, regasification, and combustion). Moreover, it is based on data from primary and secondary sources, mainly the Ecoinvent database and the ReCiPe 2016 method. For OCGT, the results showed that the BR-NGF power plant and the natural gas life cycles are responsible for 620.87 gCO2eq./kWh and 178.58 gCO2eq./kWh, respectively. For CCGT, these values are 450.04 gCO2eq./kWh and 129.30 gCO2eq./kWh. Our findings highlight the relevance of the natural gas’ life cycle, signaling additional opportunities for reducing the overall carbon footprint of natural gas-fired power generation.

Energy and Exergy-Based Modeling and Performance Evaluation of a Natural Gas-Fired Combined-Cycle Power Plant

Energy and Exergy-Based Modeling and Performance Evaluation of a Natural Gas-Fired Combined-Cycle Power Plant

Optimizing lean and rich Vapor compression with solar Assistance for post-combustion carbon capture in natural gas-fired power plant

The integration of post-combustion capture (PCC) CO2 technologies with power plants and high-emission industrial processes has become imperative for reducing carbon emissions and mitigating environmental impacts. This study focuses on addressing the significant energy consumption associated with PCC and explores the potential of using solar thermal energy to optimize configurations, thereby enhancing sustainability and reducing dependency on conventional power sources. Simulate various configurations under steady-state conditions using Aspen HYSYS V11 and Aspen Economic Evaluation software. The results indicate a substantial reduction in energy consumption to 2.1 GJ/ton CO2 after the initial optimization steps. The key innovations involve the integration of Lean Vapor Compression (LVC), Solvent Split Flow (SSF), Rich Solvent Recycle (RSR), and Rich Vapor Compression (RVC). Further optimization was conducted by integrating a reboiler with parabolic trough collectors (PTC), to reduce energy penalties. The LVC + RVC + RSR + SSF + PTC configuration results reveal a notable improvement in exergoeconomic factors, ranging from 3.13% to 7.8%, highlighting the economic feasibility of the optimized configurations. Simultaneously, the energy penalty decreased by 11.1%, signifying enhanced sustainability in the proposed PCC system. This study contributes to the gap in research by demonstrating the efficacy of solar thermal energy in optimizing PCC configurations, providing a pathway towards more sustainable and energy-efficient solutions for carbon capture in high-emission industrial sectors. The findings offer insights for researchers, engineers, and policymakers aiming to address the pressing issue of carbon emissions from industrial processes.

Particulate matter concentrations around natural gas-fired power plants and their associated health impact assessment

The quantification and prediction of particulate matter (PM) concentrations in the air are essential due to their negative impacts on human health and the environment. This study quantified PM concentrations and associated health effects at four natural gas-based power plants in Bangladesh. The measurement of PM2.5 and PM10 using the respirable dust samplers APS-113NL and APS-113BL, respectively from the year of 2015 to 2021 revealed that the concentration of both types of particles fluctuated over the years. The highest recorded levels of particles were in 2019, with PM2.5 at 126 µg/m3 and PM10 at 283 µg/m3 and the lowest recorded levels of particles were in 2017, with PM2.5 at 76.3 µg/m3 and PM10 at 203.3 µg/m3. In 2021, PM2.5 and PM10 concentrations were 88.5 and 225 µg/m3, respectively, lower than in the past two years. Statistical modeling assessed atmospheric contaminants analyzed time series data, and projected air quality. ARIMA, ETS, and ANN modeling methods have been used to predict the monthly average of PM2.5 and PM10 concentrations. RMSE, MAPE, MASE, and MAE have been utilized for model orders, time series analysis, and forecasting validation. There is a significant variation between the forecasting models and forecasts for average PM2.5 and PM10 concentrations in natural gas-fired power plants from 2022 to 2024. This study also conducted a face-to-face interview with over 100 employees using a structured questionnaire to assess the health effects they are facing due to poor air quality in the power generation complex and found that 2 and 13 % of employees had respiratory and skin issues, respectively. Nonetheless, regular health checks, air filtration, and renewable energy consumption may benefit residents and the environment.

Development a policy for the production of Bitcoins with renewable energy sources

Bitcoin, the first decentralized digital currency introduced by an anonymous person or group since 2008, has attracted worldwide attention. A significant number of economists have introduced Bitcoin as a new phenomenon in the 21st century that could reduce global inflation. Given the tens of thousands of digital currencies that have emerged since the advent of Bitcoin and its price growth trend over more than a decade, which are signs of the growth of this business. In addition to being money, Bitcoin has always been considered a tool for investing and storing value, which is why it is called digital gold. One of the most important problems in the production or extraction of Bitcoins is the high-power consumption by miners. If the energy sources of electricity generation are supplied by non-renewable energy sources, in addition to emitting air pollutant gases, it will increase greenhouse gases and consequently contribute to climate change. In this research, based on the idea of the authors, which is that the economic support of Bitcoin is energy, a strategy for producing Bitcoin from renewable energy sources is considered. First, the amount of electrical energy consumption by Bitcoin production is calculated based on statistical data, and then based on the price of electricity in different countries of the world and its global average, the base price of Bitcoin is calculated. In the following, four scenarios are proposed for the production of Bitcoin by electricity supplied from non-renewable energy sources. These scenarios include coal-fired steam power plants, natural gas-fired power plants, natural gas/oil gas-fired power plants, and dual-cycle (steam and gas cycles) natural gas-fired power plants. Based on the amount of electricity required to produce one Bitcoin, the amount of pollutants emitted to produce Bitcoin and its social costs are calculated. These costs should be added to the base cost of Bitcoin production if non-renewable energy sources are used to produce Bitcoin. Then, renewable energy sources for Bitcoin production based on the price of electricity generated by renewable energy sources are examined. Based on the analyses, how to choose the best renewable energy source to produce Bitcoin is presented as a scenario. This article briefly answers two key questions: 1. At what price of Bitcoin is it cost-effective for governments to produce it? 2. What is the best renewable energy source to produce it? These two questions can be useful in creating a roadmap and strategy for economists and governments.

Thermal energy storage performance of biaxial voided RCC roof slab integrated with macroencapsulated PCM for passive cooling of buildings

Building space heating and cooling power consumption is growing due to population and economic growth. Integrating phase change materials (PCMs) into various building envelope components is being explored to enhance thermal energy storage capacities. Specifically, roofs exposed to direct sunlight significantly promote thermal energy transfer to the interior, increasing the space heating and cooling requirements. In this study, thermal energy storage performance of a biaxial voided roof slab integrated with PCM is experimentally investigated under ambient conditions and compared with a normal reinforced concrete (RCC) without PCM. PCM selection, characterization, and metal void former development are performed, followed by macroencapsulation and integration into the roof slab. Thermal performance measures are evaluated, including temperature profile, heat flux, thermal load, time lag, and decrement factor. Financial viability indicators such as electricity cost savings, payback period, and CO2 emissions savings are also assessed. The results show PCM integrated biaxial voided roof slab reduces interior temperature by upto 7.2 °C during sunny hours, heat transfer to the interior by upto 60.6 %, and thermal load by upto 54 %. In addition, considering heating and cooling, it offers an average daily saving of 0.06 USD/kWh/m2 and a payback period of about 5.7 years. Further, it gives CO2 emissions savings of upto 13.7, 12.3, and 4.3 kgCO2/kWh for lignite-, coal-, and natural gas-fired power plants. Furthermore, its mean time lag is 4.2 h, with a decrement factor of 0.75 compared to 3.9 h and 0.85 for the normal RCC unit. The study makes significant contribution to knowledge by providing a unique, simple yet highly effective PCM macroencapsulation integration technique for roof slabs and insights into its thermal performance under the hot weather conditions.

Optimizing post-combustion carbon capture: A comprehensive 3E analyses of energy, exergy, and exergoeconomic aspects with solar integration

The combination of capturing CO2 from power plants and storing it has the potential to mitigate the effects of fossil fuel usage on the climate. The reduction of CO2 emissions through CCS is recognized as a viable solution, but the significant challenge lies in the need to reduce costs and energy consumption in its development. A method that can be utilized to improve the energy efficiency of capture is the implementation of exergy-based analysis, which includes both exergetic and exergoeconomic analyses. This study aims to create an exergy-based assessment of a post-combustion CO2 capture with DGA 50 wt% solvent, using ASPEN HYSYS Version 11 for a Natural Gas-fired power plant with a capture rate of 90 %. The results show that through meticulous modifications in the system's configuration, including LVC, SSF, RVC, RSR, ICA, and their combinations, the reboiler's energy consumption was significantly reduced from 11.1 GJ/Ton CO2 to 3.27 GJ/Ton CO2, and the utility consumption was reduced by approximately 6,500$/h. Additionally, we compared various configurations in terms of exergy and exergoeconomic. The plant exergy efficiency improved from 44.9 % in the standard configuration to 68.3 % for the LVC + Solar configuration. Additionally, the exergoeconomic factor improved from 3.1 % to 3.8 %.

Energy and exergy analysis of the 1220 MW natural gas-fired Hamitabat combined cycle power plant

In this study, the energy and exergy analysis of the 1220 MW Hamitabat combined cycle power plant (CCPP) that was renovated in 2017 with a 520 million € project is carried out. A thermodynamic model is built by applying the conservation of mass and energy principles and operating data are obtained from the plant operators. Exergy analysis is performed with the exergy balance equation to determine the exergy efficiencies and improvement potentials of all components. Also, parametric analyses are carried out to investigate the methods to enhance the performance of the plant. The plant has thermal and exergy efficiencies of 59.70% and 58.52%, respectively and these values are 13.70% and 13.52% higher than the thermal and exergy efficiencies of the original plant, respectively. Results showed that the combustion chamber (CC) has the highest rate of exergy destruction, and it is responsible for 77.61% of the total irreversibilities. The improvement potential of the CC is found to be 67.992 MW, and the prevention of heat loss from CC can increase the thermal and exergy efficiencies of the plant by 3.88% and 3.80%, respectively. Parametric analyses showed that the plant performance can be enhanced by increasing the inlet temperatures of high- and intermediate-pressure turbines, and decreasing the pressures of condenser and high-pressure turbine.

Thermoexergetic analysis and response optimisation of selective exhaust gas recirculation with solvent-based CO2 capture in a natural gas-fired combined cycle power plant

Thermoexergetic analysis and response optimisation of selective exhaust gas recirculation with solvent-based CO2 capture in a natural gas-fired combined cycle power plant

Evaluation of a tetramine-appended MOF for post combustion CO[formula omitted] capture from natural gas combined cycle flue gas by steam-assisted temperature swing adsorption

A novel tetraamine-appended metal–organic framework (MOF), exhibiting double-stepped isotherm was explored in a 3-step steam-assisted temperature swing adsorption process (SA-TSA) for CO2 removal from dry flue gas emitted from natural gas-fired power plants (NGCC). The reported material exhibited properties highly suited for CO2 capture from dilute sources. Extensive numerical simulations were performed to comprehend the impact of isotherm shape, heat transfer coefficient, feed temperature and heat capacity of solid on adsorption and desorption dynamics in a fixed bed. A multi-objective optimization was performed to identify operating conditions that achieve low steam consumption and high productivity while maintaining high purity (≥95%) and high recovery (≥90%). It was found that high purity and high recovery are obtained only when the process is isothermal. Thermal fronts propagating through the column impact the process performance. We show that the process cannot achieve recovery targets, i.e., ≥90%, unless heat is removed from the system rapidly. The lowest achievable specific steam consumption is ≈45kgsteamkgCO2−1 and highest achievable productivity is ≈0.1molco2madsorbent−3s−1 in an isothermal scenario.

Operating Strategy of LNG Terminal in Interdependent Electricity and Natural Gas Markets

With the ever strengthening interdependence between electricity and natural gas (NG) systems, the outcomes of the two energy markets could be affected by market entities from both markets. The existing studies mainly discuss the strategic behaviors of market entities participating in directly the two energy markets, lacking the concentration on the market entities participating in one single market while they could still pose impacts on the other market via the interdependence between the two markets. This paper studies the operating strategy of liquified NG (LNG) terminal, by describing the problem as a NG market game and an electricity market game. The problem is then reformulated as a bi-level single-leader multi-follower mix-integer programming (MIP) model where the LNG terminal acts as the leader while the NG fired power plants (NGPPs) as the followers. The model could be converted to a single-level one with the value-function method, and the interaction between the leader and followers is addressed with the sample-based algorithm, combined with the diagonalization algorithm to find the equilibrium among followers. The case studies further demonstrate the feasibility and effectiveness of the proposed methodology and illustrate the outcomes of the interdependent electricity and NG markets with the strategic LNG terminal.

Optimal sizing toolbox for energy generation and storage for a nuclear hybrid microgrid

Background In recent years, renewable energy sources, such as wind, have contributed to a decrease in grid stability. This has created the need for flexible and reliable back-up energy generation. Currently this role is fulfilled by natural gas-fired power plants that are able to quickly adjust power output based on present needs. Nuclear power presents an option for a clean and reliable alternative to these natural gas-fired power plants. However, nuclear power alone is unable to provide flexible enough power generation to fill this role. Instead, nuclear power plants must be combined with strategically sized energy storage systems to effectively complement the renewable power generation. Grids such as these are generally simulated using deterministic models which are unable to account for quickly fluctuating wind power generation. This in turn creates unsafe ramp rates for the nuclear power plant. Methods The approach taken in this paper utilizes a continuous-time stochastic model to simulate a grid with wind generation, nuclear power, and an energy storage system as the only energy sources. This paper focuses on this model and a development of a GUI to form a grid sizing toolbox. This toolbox was then demonstrated with an isolated microgrid using year-long wind and load data. Wind penetration, nuclear ramp rate limitations, and storage types were all varied to observe different scenarios and determine optimal storage sizing. Results There were several outcomes from this study that can inform grid planning. Nuclear power plant size trends downwards with greater wind power generation. However, high variability of wind power limits the size reduction. Nuclear capacity factor is between 41% to 57%, dropping further as wind penetration was increased. This highlights the difficulty of maintaining high utilization in these scenarios. Conclusions All storage types had similar performance in all categories except size, in which pumped hydroelectric and compressed air storage required smaller storage sizes.

Advancing power plant decarbonization with a flexible hybrid carbon capture system

Carbon dioxide capturing from natural gas-fired power plants is challenging due to high flow rate and the low carbon dioxide concentration of flue gas. This is an emerging field where many concepts and scientific principles are still in development. In this paper, a novel design is proposed for decarbonizing a natural gas-fired combined cycle power plant using a solar-assisted hybrid membrane-amine carbon capture and storage system. The design incorporates a solar field with thermal energy storage integrated with the capture plant reboiler along with multi-stage carbon dioxide selective membrane modules for selective exhaust gas recirculation (SEGR) combined with exhaust gas recirculation (EGR) to increase the concentration of Carbon dioxide in the flue gas. It is hypothesized that the proposed design could enhance the performance of the power plant integrated with carbon capture in terms of flexibility and sustainability. In this regard, a comprehensive process modeling and simulation framework is developed to accurately investigate the interactions between different components of the integrated process. The results show that the carbon dioxide concentration in the flue gas increases from 3.9 mol% in the conventional power plant to 10.87 mol% in the EGR + SEGR case (26 % of flue gas to EGR and 50 % to SEGR) and increases to 18.08 mol% by the SEGR case (76 % of flue gas to SEGR). Solar thermal energy is an efficient solution for reducing or eliminating the need for steam extraction for the stripper reboiler, resulting in a significant increase in net power output compared to the non-solar cases. The proposed designs lead to a 19.4 % increase in system power output in the SEGR case and a 13.8 % increase in the EGR + SEGR case compared to the baseline case. Also, the specific reboiler duty and required packing material volume in the absorber and stripper are significantly improved in the proposed designs. Moreover, the power plant carbon intensity in the proposed designs can be reduced by up to 10.3 %. The EGR + SEGR case offers an optimal solution as it requires a significantly smaller membrane area, approximately 71 % smaller membrane area compared to SEGR. The proposed designs and analysis have the potential to contribute significantly to the decarbonization of fossil-fueled power plants and enhance the sustainability and flexibility of the power sector.

Environmental impact assessment of an air-to-water heat pump through the expanded total equivalent warming impact index based on experimental data

The Total Equivalent Warming Impact (TEWI) index is conventionally used to evaluate emissions from heating, ventilation, air conditioning and refrigeration (HVAC&R) systems. However, a more comprehensive indicator, the Expanded Total Equivalent Warming Impact (ETEWI), has been proposed to overcome the limits of TEWI index and to consider additional environmental impacts such as the effects of urban heat island and the natural gas losses along high-pressure pipelines supplying gaseous fuel to natural gas-fired power plants. In this study, TEWI and ETEWI metrics are applied to an air-to-water electric heat pump (EHP) serving a university building in Benevento (Southern Italy). Real data on EHP electricity consumption have been derived from the entire building's electric load and compared to measured data. ETEWI index has been estimated in two scenarios, one considering the impact of refrigerant charge variation on the performance of the EHP and its environmental impact and the other disregarding it. Additionally, carbon dioxide emission factors for electricity production have been forecasted from 2021 to 2033 to determine the indirect term of ETEWI index. Over the lifetime of the EHP, ETEWI increases by 4.8% compared to TEWI when the variation of refrigerant charge level is not considered. However, this percentage growth is equal to 6.5% when the impact of refrigerant charge change is accounted too. In the latter scenario, the indirect term of ETEWI decreases from 22.7 tCO2 in 2015 to 12.0 tCO2 in 2033 when the forecast of the carbon dioxide emission factors for electricity production is taken into account.

Energy, exergy, and economic evaluation of integrated waste incineration facility with a thermal power plant

Increased waste production and poor waste management have created severe negative environmental impacts. Waste incineration is a way to produce energy and decreases environmental impacts; however, this technique cannot be considered independently as a source of power generation because of its low performance. This study aims to evaluate the integration of a waste incineration system with a natural gas-fired power plant in terms of energy, exergy, and economic points. As a result of the proposed configurations, in addition to promoting efficiency and net power production, some equipment is removed from power plants. Efforts are made to increase the accuracy of simulation results by paying attention to the combustion process in boilers and predicting the actual working condition of feed water heaters. Results showed that the hybrid scheme improves electricity generation by up to 2.87 MW and boosts energy, and exergy efficiency by up to 0.32%, and 0.3%, respectively.

Integration of adsorption based post-combustion carbon dioxide capture for a natural gas-fired combined heat and power plant

This paper proposes a continuous CO2 capture system for natural gas combined heat and power (CHP) facility and explores the potential of low-temperature vacuum-swing adsorption (VSA) process for post-combustion CO2 capture (PCC) in the context of carbon capture and storage (CCS). Although VSA has strong potential for efficient CO2 capture in district-scale energy systems, previous case studies have largely focused on high-emission coal combustion sources, making VSA application challenging for these conditions. We address this issue by theoretically designing a ready-to-operate flue gas cleaning process with CCS for a medium-sized 4.3 MW natural gas CHP operating in the local industry. Our in-depth analysis examines the most critical parts such as dehydration, involving condenser and temperature-swing adsorption (TSA), and CO2 capture via VSA. The conceptual design and performance of VSA are approached by developing a mathematical model to estimate the technology size and performance. This work shows that utilising a small fraction of heat recovered from CHP-generated flue gas is sufficient to supply the necessary heat for auxiliary units, and that using natural cooling water for dehydration effectively reduces moisture (87 vol%) and energy demand for final dehydration via TSA. Furthermore, it demonstrates that 4-step VSA consisting of 15 columns using zeolite 13X can separate CO2 with a desired purity of 90.4%, meeting the requirements for CO2 storage and transportation onshore, at a 15.6% recovery rate. The cost of achieving high CO2 purity without pre-pressurising the CO2-rich flue gas, while maintaining cycle simplicity, is discussed. Overall, our paper provides a comprehensive approach to retrofitting distract-scale power plants with CO2-lean emissions, presenting a ready-to-operate flue gas cleaning technology based on real operating conditions and technical restrictions, which can contribute towards decarbonisation.

The price and income elasticities of natural gas demand in Azerbaijan: Is there room to export more?

Natural gas is frequently introduced as a “transitional fuel”. Because burning natural gas emits less carbon dioxide emissions than burning either oil or coal. Additionally, the intermittent nature of low-carbon electricity generation creates imperative for using natural gas for power generation. The role of natural gas is currently under scrutiny as climate change transforms into a climate crisis. Meanwhile, share of natural gas in the primary energy consumption of Azerbaijan is 69%, while 94% of the country’s electricity is currently being generated in natural gas-fired power plants. In this manner, this paper estimates income and price elasticities of natural gas demand for the Azerbaijan case. In this study, various sets of estimation techniques are utilized. By modeling natural gas demand with different estimation methods, including Autoregressive Distributed Lagged Structural Time Series Modeling, Dynamic Ordinary Least Squares Method, Fully Modified Ordinary Least Squares, Canonical Cointegrating Regression, and General to Specific under Autometrics multi-path search machine learning algorithm, we try to find if there is room for the country to export more. All these utilized estimation methods confirmed the long-run income elasticity to be around 0.8, while the long-run price elasticity is around −0.1. Both estimations provide insights in terms of energy security and electricity security for policymakers during the implementation process of climate, energy, and environmental policy. Findings of this study classify natural as a necessity and normal good for the Azerbaijan case. The main policy implication of this study is that policymakers must enable and facilitate the availability of close renewable substitutes for residential and commercial customers. Estimated elasticities suggest that with rising national income, demand for natural gas will keep increasing, and efficient consumption will not be attainable with increasing prices. In the pursuit of export potential, findings suggest that it is more relevant to free up natural gas allocated from power generation by substituting it with renewable energy sources.

Life cycle multi-objective (geospatial, techno-economic, and environmental) feasibility and potential assessment of utility scale photovoltaic power plants

Bridging the gap between sustainability theory and good practice of utility-scale photovoltaic deployment requires strategic planning considering multiple criteria. This study, for the first time, integrates meteorological and air quality parameters and lifecycle costs and environmental emissions with geospatial, techno-economic parameters in determining potential and suitability of photovoltaic power plants. For two system orientations, technical potential based on timeseries of meteorological parameters is estimated after development of irradiance and aerosol optical depth maps. Besides others, project lifecycle and water-use costs are introduced in levelized cost of electricity calculation. Site suitability is estimated based on site-specific techno-economic parameters and annual dust load. Lastly, comparison between lifecycle environmental impacts, considering twelve different indicators of proposed plant and natural-gas fired power plant (as reference) is performed for different capacity powerplants. Cumulative resource potential ranging from 7497 to 14141 GW is identified for Pakistan. Levelized Cost of Electricity is in range of 0.026–0.041 USD/kWh, highly competitive with global estimates and less than the residential tariff in the country. Major contribution (∼81%) to the cost estimates is made by capital generation whereas the second highest is by infrastructure-parity components (∼12%). With inclusion of aerosol optical depth in site suitability analysis, the extremely suitable class area decreases by 3.81%. Overall, net environmental impact avoided over the lifecycle increases with increase in rated capacity following a logistic curve, and is approximately 5 and 10 times higher for 50 and 100 MW power plants, respectively.

Towards nearly zero emissions natural gas-fired power plants using cryogenic carbon dioxide capture technology

Cryogenic carbon capture (CCC) is one of the most recent and promising technologies for reducing carbon dioxide emissions, hence mitigating the global warming. The present research aims at exploring the feasibility of integrating it into existing thermal power plants in Egypt that are commonly operated by natural gas.A simulation model is developed using Aspen Plus Dynamics software to accurately predict the behavior of the thermal power plant after applying such integration. The model incorporates the CCC cycle established by Sustainable Energy Solutions into a natural gas power plant of Abu Qir, Egypt. The integral plant is benchmarked at various part loads scenarios. The study investigates the ability of capturing up to 99% of the emitted CO2 and determines the consequent penalties in the generated power and the overall thermal efficiency.The results demonstrated successful integration of the thermal power plant and the CCC revealing smooth operation and safe transition between different part loads. By capturing 99% of the emitted CO2, both the generated power and the overall efficiency dropped maximally by 10.73%. The integration led to a maximum energy penalty of 0.840 MJe/kgCO2 which is much smaller than other conventional carbon capture techniques.Applying this technology to all thermal power plants in Egypt, about 89 M tonnes of CO2 emissions will be captured annually. Further integrations of CCC-ECL into other chemical and industrial facilities would significantly lead to a cleaner environment.

Predicting solvent degradation in absorption–based CO2 capture from industrial flue gases

This work aims to predict solvent degradation rates in absorption-based CO2 capture processes using a 30 wt% aqueous monoethanolamine (MEA) solvent. A degradation model for MEA is developed and used to predict solvent degradation in full-scale capture processes. Mass transfer resistances and the solubility of O2 are considered to obtain a generalized and consistent degradation model. Degradation is evaluated for the capture process for flue gases with typical industrial compositions; a natural gas-fired power plant, a waste-to-energy plant, a coal-fired– power plant, and a cement plant. The impact of process modifications, such as absorber intercooling, dissolved O2 removal, a reduction in solvent residence times, and increased stripper pressures on degradation is evaluated.The predicted degradation rate in the capture processes is approximately 90 to 150 g MEA/ton CO2 captured, and the composition of the flue gas was found to have a significant influence on the distribution of degradation throughout the process. Modifications to the process can significantly affect the overall degradation rate. Both absorber intercooling and removal of dissolved O2 may reduce the overall degradation by up to 40%, depending on the composition of the flue gas. A reduction in solvent residence times or pressure in the stripper has limited effects on the degradation in the case of MEA, because of the amine’s relatively low stability towards oxidative degradation. However, these process modifications look promising for more stable solvents.