CO2 capture from power plants: Part I. A parametric study of the technical performance based on monoethanolamine

Capture and storage of CO₂ from fossil fuel fired power plants is drawing increasing interest as a potential method for the control of greenhouse gas emissions. An optimization and technical parameter study for a CO₂ capture process from flue gas of a 600 MWe bituminous coal fired power plant, based on absorption/desorption process with MEA solutions, using ASPEN Plus with the RADFRAC subroutine, was performed. This optimization aimed to reduce the energy requirement for solvent regeneration, by investigating the effects of CO₂ removal percentage, MEA concentration, lean solvent loading, stripper operating pressure and lean solvent temperature.Major energy savings can be realized by optimizing the lean solvent loading, the amine solvent concentration as well as the stripper operating pressure. A minimum thermal energy requirement was found at a lean MEA loading of 0.3, using a 40 wt.% MEA solution and a stripper operating pressure of 210 kPa, resulting in a thermal energy requirement of 3.0 GJ/ton CO₂, which is 23% lower than the base case of 3.9 GJ/ton CO₂. Although the solvent process conditions might not be realisable for MEA due to constraints imposed by corrosion and solvent degradation, the results show that a parametric study will point towards possibilities for process optimisation.     

Techno-economic study of CO2 capture from natural gas based hydrogen plants

Canadian oil sands are considered to be the second largest oil reserves in the world. However, the upgrading of bitumen from oil sands to synthetic crude oil (SCO) requires nearly ten times more hydrogen (H₂) than conventional crude oils. The current H₂ demand for oil sands operations is met mostly by steam reforming of natural gas (SMR). The future expansion of oil sands operations is likely to quadruple the demand of H₂ for oil sand operations in the next decade.This paper presents modified process schemes that capture CO₂ at minimum energy penalty in modern SMR plants. The approach is to simulate a base case H₂ plant without CO₂ capture and then look for the best operating conditions that minimize the energy penalty associated with CO₂ capture while maximizing H₂ production. The two CO₂ capture schemes evaluated in this study include a membrane separation process and the monoethanolamine (MEA) absorption process. A low energy penalty is observed when there is lower CO₂ production and higher steam production. The process simulation results show that the H₂ plant with CO₂ capture has to be operated at lower steam to carbon ratio (S/C), higher inlet temperature of the SMR and lower inlet temperatures for the water gas-shift (WGS) converters to attain lowest energy penalty. Also it is observed that both CO₂ capture processes, the membrane process and the MEA absorption process, are comparable in terms of energy penalty and CO₂ avoided when both are operated at conditions where lowest energy penalty exists.     

CO2 capture from coal-fired power plants based on sodium carbonate slurry; a systems feasibility and sensitivity study

In this work the feasibility of a CO₂ capture system based on sodium carbonate–bicarbonate slurry and its integration with a power plant is studied. The results are compared to monoethanolamine (MEA)-based capture systems. Condensing power plant and combined heat and power plant with CO₂ capture is modelled to study the feasibility of combined heat and power plant for CO₂ capture.Environmental friendly sodium carbonate would be an interesting chemical for CO₂ capture. Sodium carbonate absorbs CO₂ forming sodium bicarbonate. The low solubility of sodium bicarbonate is a weak point for the sodium carbonate based liquid systems since it limits the total concentration of carbonate. In this study the formation of solid bicarbonate is allowed, thus forming slurry, which can increase the capacity of the solvent. With this the energy requirement of stripping of the solvent could potentially be around 3.22 MJ/kg of captured CO₂ which is significantly lower than with MEA based systems which typically have energy consumption around 3.8 MJ/kg of captured CO₂.Combined heat and power plants seem to be attractive for CO₂ capture because of the high total energy efficiency of the plants. In a condensing power plant the CO₂ capture decreases directly the electricity production whereas in a combined heat and power plant the loss can be divided between district heat and electricity according to demand.     

Pre-combustion CO2 capture from natural gas power plants,with ATR and MDEA processes

Among the various configurations of fossil fuel power plants with carbon capture, this paper focuses on pre-combustion techniques applied to natural gas combined cycles. With more detail, the plant configuration here addressed includes: (i) the steam reforming of natural gas, based on an air-blown autothermal process, following a recuperative pre-reforming treatment, (ii) the water gas shift producing CO₂ and H₂, (iii) the separation of CO₂ by means of a mixed physical–chemical absorption system using a MDEA solution, and (iv) a hydrogen fuelled combined cycle.Similar configurations have been studied quite extensively, being among the most attractive for full-scale realizations in a near-mid term future. This paper proposes a detailed thermodynamic study and optimization of the plant configuration, bringing to a reliable performance estimation based on today's best available technology as far as the various plant sections are concerned (gas and steam turbine, natural gas reforming process, CO₂ separation). The predicted LHV efficiency for the base configuration is about 50%. Being this value at the top of the range quoted in the open literature studies (35–50%), the paper includes a quite extensive sensitivity analysis, showing that more conservative assumptions may bring to significantly poorer performance, especially considering the pretty large number of operating parameters involved in the process.     

Use of experience curves to estimate the future cost of power plants with CO2 capture

Given the dominance of power plant emissions of greenhouse gases, and the growing worldwide interest in CO₂ capture and storage (CCS) as a potential climate change mitigation option, the expected future cost of power plants with CO₂ capture is of significant interest. Reductions in the cost of technologies as a result of learning-by-doing, R&D investments and other factors have been observed over many decades. This study uses historical experience curves as the basis for estimating future cost trends for four types of electric power plants equipped with CO₂ capture systems: pulverized coal (PC) and natural gas combined cycle (NGCC) plants with post-combustion CO₂ capture; coal-based integrated gasification combined cycle (IGCC) plants with pre-combustion capture; and coal-fired oxyfuel combustion for new PC plants. We first assess the rates of cost reductions achieved by other energy and environmental process technologies in the past. Then, by analogy with leading capture plant designs, we estimate future cost reductions that might be achieved by power plants employing CO₂ capture. Effects of uncertainties in key parameters on projected cost reductions also are evaluated via sensitivity analysis.     

Assessing the value of CO2 capture ready in new-build pulverised coal-fired power plants in China

Making new plants CO₂ capture ready (CCR) would enable them to retrofit to capture CO₂ at a later date at lower cost when the appropriate policy and/or economic drivers are in place. In order to understand the economic value and investment characteristics of making new plants CCR in China, a typical 600 MW pulverised coal-fired ultra-supercritical power plant, locating in Guangdong province, was examined. Combined with an engineering assessment, costs were estimated for different CCR scenarios. To analyze CCR investment opportunities, the paper applies a cash flow model for valuing capture options and CCR investment. Results were obtained by Monte-Carlo simulation, based on engineering surveys and an IEA GHG CCR study, as well as plant performance information and expert projections on carbon prices, coal prices and electricity prices.CCR investments are justified by factors such as higher retrofitting probabilities, lower early closure probabilities and fair economic return. However, the economic case for CCR largely depends on two factors: (a) whether the original plant is retrofittable without CCR; and (b) the type of investments made, for example, investments essential to CCR tend to be more economic than additional non-essential CCR features such as clutched low pressure turbines. The carbon price and discount rate were found to have significant impacts on the economics of CCR. Overall, it appears that the value of the ‘capture options’ that CCR generates for retrofitting CCS is significant, and so could justify a modest CCR investment, even assuming the original plant is retrofittable without CCR. It was also found the value of CCR might be significantly understated if the range of potential retrofitting dates is artificially constrained.     

Effective retrofitting of post-combustion CO2 capture to coal-fired power plants and insensitivity of CO2 abatement costs to base plant efficiency

Existing coal-fired power plants were not designed to be retrofitted with carbon dioxide post-combustion capture (PCC) and have tended to be disregarded as suitable candidates for carbon capture and storage on the grounds that such a retrofit would be uneconomical. Low plant efficiency and poor performance with capture compared to new-build projects are often cited as critical barriers to capture retrofit. Steam turbine retrofit solutions are presented that can achieve effective thermodynamic integration between a post-combustion CO₂ capture plant and associated CO₂ compressors and the steam cycle of an existing retrofitted unit for a wide range of initial steam turbine designs. The relative merits of these capture retrofit integration options with respect to flexibility of the capture system and solvent upgradability will be discussed. Provided that effective capture system integration can be achieved, it can be shown that the abatement costs (or cost per tonne of CO₂ to justify capture) for retrofitting existing units is independent of the initial plant efficiency. This then means that a greater number of existing power plants are potentially suitable for successful retrofits of post-combustion capture to reduce power sector emissions. Such a wider choice of retrofit sites would also give greater scope to exploit favourable site-specific conditions for CCS, such as ready access to geological storage.     

Thermodynamic analysis on post-combustion CO2 capture of natural-gas-fired power plant

A chemical absorption, post-combustion CO₂ capture unit is simulated and an exergy analysis has been conducted, including irreversibility calculations for all process units. By pinpointing major irreversibilities, new proposals for efficient energy integrated chemical absorption process are suggested. Further, a natural-gas combined-cycle power plant with a CO₂ capture unit has been analyzed on an exergetic basis. By defining exergy balances and black-box models for plant units, investigation has been made to determine effect of each unit on the overall exergy efficiency. Simulation of the chemical absorption plant was done using UniSim Design software with Amines Property Package. For natural-gas combined-cycle design, GT PRO software (Thermoflow, Inc.) has been used. For exergy calculations, spreadsheets are created with Microsoft Excel by importing data from UniSim and GT PRO. Results show the exergy efficiency of 21.2% for the chemical absorption CO₂ capture unit and 67% for the CO₂ compression unit. The total exergy efficiency of CO₂ capture and compression unit is 31.6%.     

A novel process integration,optimization and design approach for large-scale implementation of oxy-fired coal power plants with CO2 capture

The widespread use of fossil fuels within the current energy infrastructure is considered as the largest source of anthropogenic emissions of carbon dioxide, which is largely blamed for global warming and climate change. At the current state of development, the risks and costs of non-fossil energy alternatives, such as nuclear, biomass, solar, and wind energy, are so high that they cannot replace the entire share of fossil fuels in the near future timeframe. Additionally, any rapid change towards non-fossil energy sources, even if possible, would result in large disruptions to the existing energy supply infrastructure. As an alternative, the existing and new fossil fuel-based plants can be modified or designed to be either “capture” or “capture-ready” plants in order to reduce their emission intensity through the capture and permanent storage of carbon dioxide in geological formations. This would give the coal-fired power generation units the option to sustain their operations for longer time, while meeting the stringent environmental regulations on air pollutants and carbon emissions in years to come.Currently, there are three main approaches to capturing CO₂ from the combustion of fossil fuels, namely, pre-combustion capture, post-combustion capture, and oxy-fuel combustion. Among these technology options, oxy-fuel combustion provides an elegant approach to CO₂ capture. In this approach, by replacing air with oxygen in the combustion process, a CO₂-rich flue gas stream is produced that can be readily compressed for pipeline transport and storage. In this paper, we propose a new approach that allows air to be partially used in the oxy-fired coal power plants. In this novel approach, the air can be used to carry the coal from the mills to the boiler (similar to the conventional air-fired coal power plants), while O₂ is added to the secondary recycle flow as well as directly to the combustion zone (if needed). From a practical point of view, this approach eliminates problems with the primary recycle and also lessens concerns about the air leakage into the system. At the same time, it allows the boiler and its back-end piping to operate under slight suction; this avoids the potential danger to the plant operators and equipment due to possible exposure to hot combustion gases, CO₂ and particulates. As well, by integrating oxy-fuel system components and optimizing the overall process over a wide range of operating conditions, an optimum or near-optimum design can be achieved that is both cost-effective and practical for large-scale implementation of oxy-fired coal power plants.     

Integration of CO2 capture unit using single- and blended-amines into supercritical coal-fired power plants: Implications for emission and energy management

This work provides the essential information and approaches for integration of carbon dioxide (CO₂) capture units into power plants, particularly the supercritical type, so that energy utilization and CO₂ emissions can be well managed in the subject power plants. An in-house model, developed at the University of Regina, Canada, was successfully used for simulating a 500 MW supercritical coal-fired power plant with a post-combustion CO₂ capture unit. The simulations enabled sensitivity and parametric study of the net efficiency of the power plant, the coal consumption rate, and the amounts of CO₂ captured and avoided. The parameters of interest include CO₂ capture efficiency, type of coal, flue gas delivery scheme, type of amine used in the capture unit, and steam pressure supplied to the capture unit for solvent regeneration. The results show that the advancement of MEA-based CO₂ capture units through uses of blended monoethanolamine–methyldiethanolamine (MEA–MDEA) and split flow configuration can potentially make the integration of power plant and CO₂ capture unit less energy intensive. Despite the increase in energy penalty, it may be worth capturing CO₂ at a higher efficiency to achieve greater CO₂ emissions avoided. The flue gas delivery scheme and the steam pressure drawn from the power plant to the CO₂ capture unit should be considered for process integration.     

Long-term coal gasification-based power plants with near-zero emissions. Part A: Zecomix cycle

These two part papers analyse three plant configurations for high efficiency, near-zero emissions power generation from coal, suitable for long-term installations. In the first part the Zecomix cycle, a novel power plant based on various innovative processes, is presented. Zecomix plant is based on a coal hydrogasification process, using recycled steam and hydrogen as gasifying agents, to produce a CH₄ rich syngas. Methane is then converted to an H₂/H₂O based syngas and CO₂ is captured, by reacting in two carbonator reactors with CaO-based solid sorbent. CaCO₃ produced in carbonators is thermally regenerated in a calciner. The synthetic fuel is burned with oxygen in a semi-closed high temperature steam cycle, with a supercritical heat recovery.The paper presents a detailed analysis of the thermodynamic aspects of the process, with the scope of assessing its potential performance in terms of efficiency and emissions. Main operating parameters of the chemical island (e.g. hydrogasifier and calciner pressure, steam flow rates to carbonators, syngas recycle fraction) and of the power island (e.g. pressure ratio, turbine inlet temperature and reheat pressure) were varied in order to evaluate their effect on plant performance and to optimize the process. Critical issues are specifically discussed: the calcination process, the calcium oxide utilization in carbonators, the cooling requirement of the high temperature turbine, the presence of incondensable species in the steam cycle. An accurate performance estimation is therefore developed by considering advanced components, as an evolution of today's technology, excluding unproven devices whose feasibility cannot be anticipated.Depending on sorbent utilization, a net plant efficiency of 44–47% with a virtually complete carbon capture was obtained, a very interesting result with respect to other proposed coal-fired power plants with carbon capture. The high complexity of the chemical island and the importance of a good sorbent performance should be however taken into account for a fair comparison with other plant concepts. Further experimental investigations are mandatory to demonstrate the technical and economical feasibility of the Zecomix plant.     

Pathways towards large-scale implementation of CO2 capture and storage: A case study for the Netherlands

We sketch four possible pathways how carbon dioxide capture and storage (CCS) (r)evolution may occur in the Netherlands, after which the implications in terms of CO₂ stored and avoided, costs and infrastructural requirements are quantified. CCS may play a significant role in decarbonising the Dutch energy and industrial sector, which currently emits nearly 100 Mt CO₂/year. We found that 15 Mt CO₂ could be avoided annually by 2020, provided some of the larger gas fields that become available the coming decade could be used for CO₂ storage. Halfway this century, the mitigation potential of CCS in the power sector, industry and transport fuel production is estimated at maximally 80–110 Mt CO₂/year, of which 60–80 Mt CO₂/year may be avoided at costs between 15 and 40 €/t CO₂, including transport and storage. Avoiding 30–60 Mt CO₂/year by means of CCS is considered realistic given the storage potential represented by Dutch gas fields, although it requires planning to assure that domestic storage capacity could be used for CO₂ storage. In an aggressive climate policy, avoiding another 50 Mt CO₂/year may be possible provided that nearly all capture opportunities that occur are taken. Storing such large amounts of CO₂ would only be possible if the Groningen gas field or large reservoirs in the British or Norwegian part of the North Sea will become available.     

Environmental impacts of absorption-based CO2 capture unit for post-combustion treatment of flue gas from coal-fired power plant

This study assesses potential environmental impacts of the absorption-based carbon dioxide (CO₂) capture unit that is integrated to coal-fired power plant for post-combustion treatment of flue gas. The assessment was performed by identifying potential pollutants and their sources as well as amounts of emissions from the CO₂ capture unit and also by reviewing toxicology, potential implications to human health and the environment, as well as the environmental laws and regulations associated with such pollutants. The assessment shows that, while offering a significant environmental benefit through a reduction of greenhouse gas emissions, the installation of CO₂ capture units for post-combustion treatment might induce unintentional and potential burdens to human health and the environment through four emission pathways, including treated gas, process wastes, fugitive emissions, and accidental releases. Such burdens nevertheless can be predetermined and properly mitigated through a well-established environmental management program and mitigation measures. Recommendations to minimize these impacts are provided in this paper.     

Exploring the potential for improvement of the energy performance of coal fired power plants with post-combustion capture of carbon dioxide

The application of post-combustion capture (PCC) processes in coal fired power stations can result in large reductions of the CO₂-emissions, but the consequential decrease in generation efficiency is an important draw-back. The leading PCC technology is based on chemical absorption processes as this technology is the one whose scale-up status is closest to full-scale capture in power plants. The energy performance of this process is analysed in this contribution. The analysis shows that the potential for improvement of the energy performance is quite large. It is demonstrated that further development of the capture technology and the power plant technology can lead to generation efficiencies for power plants with 90% CO₂ capture which are equivalent to the current generation efficiencies without CO₂ capture, i.e. 0.4 (HHV), leading to an additional resource consumption of 16%. These improvements are possible throughout a combined improvement for the capture process and power generation processes.     

Worst case scenario study to assess the environmental impact of amine emissions from a CO2 capture plant

Use of amines is one of the leading technologies for post-combustion carbon dioxide capture from gas and coal-fired power plants. This study assesses the potential environmental impact of emissions to air that result from use of monoethanol amine (MEA) as an absorption solvent for the capture of carbon dioxide (CO₂). Depending on operation conditions and installed reduction technology, emissions of MEA to the air due to solvent volatility losses are expected to be in the range of 0.01–0.8 kg/tonne CO₂ captured. Literature data for human and environmental toxicity, together with atmospheric dispersion model calculations, were used to derive maximum tolerable emissions of amines from CO₂ capture. To reflect operating conditions with typical and with elevated emissions, we defined a scenario MEA-LOW, with emissions of 40 t/year MEA and 5 t/year diethyl amine (DEYA), and a scenario MEA-HIGH, with emissions of 80 t/year MEA and 15 t/year DEYA. Maximum MEA deposition fluxes would exceed toxicity limits for aquatic organisms by about a factor of 3–7 depending on the scenario. Due to the formation of nitrosamines and nitramines, the estimated emissions of DEYA are close to or exceed safety limits for drinking water and aquatic ecosystems. The “worst case” scenario approach to determine maximum tolerable emissions of MEA and other amines is in particular useful when both expected environmental loads and the toxic effects are associated with high uncertainties.     

Location wise comparison of mixture distributions for assessment of wind power potential: A parametric study

Scientific literature discussed various types of mixture models and models derived from maximum entropy principle using short-term wind speed data for their relative assessment. The literature on suitability of these mixture models for long-term data is rarely available. However, for correct assessment of wind power potential both wind speed and wind direction are equally important. Therefore, in this paper, both wind speed and wind direction are simultaneously analyzed using several types of mixture distribution and compared the same with conventional Weibull distribution. For wind speed and wind power density assessment, the mixture distributions such as Weibull--Weibull distribution, Gamma--Weibull distribution, Truncated Normal--Weibull distribution, Truncated Normal--Normal distribution, proposed Truncated Normal--Gamma distribution and Gamma--Gamma distribution along with MEP-distribution are compared with conventional 2-parameter Weibull distribution. Similarly, for wind direction analysis, the finite mixtures of von-Mises distribution are compared with conventional von-Mises distribution. Judgment criteria include R², RMSE, Kolmogorov--Smirnov test and relative percentage error in wind power density. The sites selected are the three onshore locations of India, viz., Calcutta, Trivandrum, and Ahmedabad. The results show that for wind speed assessment, mixture distribution performs better than the conventional Weibull distribution for analyzing wind power density. However, location wise comparison of all mixture distribution is of prime importance. For wind direction analysis, finite mixture of two von-Mises distributions proved to be a suitable candidate for Indian climatology.     

An economic and environmental assessment of carbon capture and storage (CCS) power plants: a case study for the City of Kiel

In the not too distant future several power plants throughout Europe will have to be replaced and the decision has to be made whether to build coal-fired power plants with carbon capture and storage (CCS). In a study for the city of Kiel in northern Germany only an 800 MW coal power plant reaches a required minimum for rentability. This study looks at an additional economic and environmental evaluation of a coal plant with CCS. We find that in two out of three carbon and energy price scenarios integrated gasification combined cycle (IGCC) plants with CCS have the greatest rentability. Pulverised coal (PC) plants with CCS can only compete with other options under very favourable assumptions. Life-cycle emissions from CCS are less than 70% of a coal plant – compared with at least more than 80% when only considering direct emissions from plants. However, life-cycle emissions are lower than in any other assessed option.     

Derivation of correlations to evaluate the impact of retrofitted post-combustion CO2 capture processes on steam power plant performance

When integrating a post-combustion CO₂ capture process and CO₂ compression into a steam power plant, the three interface quantities heat, electricity and cooling duty must be satisfied by the power plant, leading to a loss in net efficiency. The heat duty shows to be the largest contributor to the overall net efficiency penalty of the power plant. Additional energy penalty results from the cooling and electric power duty of the capture and compression units.In this work, the dependency of the energy penalty on the quantity and quality of the heat duty is analyzed and quantified for a state-of-the-art hard coal fired power plant. Furthermore, the energy penalty attributed to the additional cooling and power duty is quantified. As a result correlations are provided which enable to predict the impact of the heat, cooling and electricity duty of post-combustion CO₂ capture processes on the net output of a steam power plant in a holistic approach.     

The acceptability of CO2 capture and storage (CCS) in Europe: An assessment of the key determining factors: Part 1. Scientific,technical and economic dimensions

The ACCSEPT project, which ran from January 2006 to December 2007, identified and analysed the main factors which have been influencing the emergence of CO₂ capture and geological storage (CCS) within the European Union (EU). The key clusters of factors concern science and technology, law and regulation, economics, and social acceptance. These factors have been analysed through interviews, a large-scale questionnaire conducted in 2006, and discussions in two stakeholder workshops (2006 and 2007). In Part I of this paper, we aim to distil the key messages and findings with regards to scientific, technical, legal and economic issues. There are no compelling scientific, technical, legal, or economic reasons why CCS could not be widely deployed in the forthcoming decades as part of a package of climate change mitigation options. In order to facilitate this deployment, governments at both the EU and Member State levels have an important role to play, in particular in establishing a robust and transparent legal framework (e.g. governing long-term environmental liability) and a strong policy framework providing sufficient and long-term incentives for CCS and CO₂ transportation networks.