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%.     

Life cycle assessment of natural gas combined cycle power plant with post-combustion carbon capture,transport and storage

Hybrid life cycle assessment has been used to assess the environmental impacts of natural gas combined cycle (NGCC) electricity generation with carbon dioxide capture and storage (CCS). The CCS chain modeled in this study consists of carbon dioxide (CO₂) capture from flue gas using monoethanolamine (MEA), pipeline transport and storage in a saline aquifer.Results show that the sequestration of 90% CO₂ from the flue gas results in avoiding 70% of CO₂ emissions to the atmosphere per kWh and reduces global warming potential (GWP) by 64%. Calculation of other environmental impacts shows the trade-offs: an increase of 43% in acidification, 35% in eutrophication, and 120–170% in various toxicity impacts. Given the assumptions employed in this analysis, emissions of MEA and formaldehyde during capture process and generation of reclaimer wastes contributes to various toxicity potentials and cause many-fold increase in the on-site direct freshwater ecotoxicity and terrestrial ecotoxicity impacts. NO_x from fuel combustion is still the dominant contributor to most direct impacts, other than toxicity potentials and GWP. It is found that the direct emission of MEA contribute little to human toxicity (HT < 1%), however it makes 16% of terrestrial ecotoxicity impact. Hazardous reclaimer waste causes significant freshwater and marine ecotoxicity impacts. Most increases in impact are due to increased fuel requirements or increased investments and operating inputs.The reductions in GWP range from 58% to 68% for the worst-case to best-case CCS system. Acidification, eutrophication and toxicity potentials show an even large range of variation in the sensitivity analysis. Decreases in energy use and solvent degradation will significantly reduce the impact in all categories.     

Life cycle assessment of a pulverized coal power plant with post-combustion capture, transport and storage of CO2

In this study the methodology of life cycle assessment has been used to assess the environmental impacts of three pulverized coal fired electricity supply chains with and without carbon capture and storage (CCS) on a cradle to grave basis. The chain with CCS comprises post-combustion CO₂ capture with monoethanolamine, compression, transport by pipeline and storage in a geological reservoir. The two reference chains represent sub-critical and state-of-the-art ultra supercritical pulverized coal fired electricity generation. For the three chains we have constructed a detailed greenhouse gas (GHG) balance, and disclosed environmental trade-offs and co-benefits due to CO₂ capture, transport and storage. Results show that, due to CCS, the GHG emissions per kWh are reduced substantially to 243 g/kWh. This is a reduction of 78 and 71% compared to the sub-critical and state-of-the-art power plant, respectively. The removal of CO₂ is partially offset by increased GHG emissions in up- and downstream processes, to a small extent (0.7 g/kWh) caused by the CCS infrastructure. An environmental co-benefit is expected following from the deeper reduction of hydrogen fluoride and hydrogen chloride emissions. Most notable environmental trade-offs are the increase in human toxicity, ozone layer depletion and fresh water ecotoxicity potential for which the CCS chain is outperformed by both other chains. The state-of-the-art power plant without CCS also shows a better score for the eutrophication, acidification and photochemical oxidation potential despite the deeper reduction of SO_x and NO_x in the CCS power plant. These reductions are offset by increased emissions in the life cycle due to the energy penalty and a factor five increase in NH₃ emissions.     

Prospects for cost-effective post-combustion CO2 capture from industrial CHPs

Industrial Combined Heat and Power plants (CHPs) are often operated at partial load conditions. If CO₂ is captured from a CHP, additional energy requirements can be fully or partly met by increasing the load. Load increase improves plant efficiency and, consequently, part of the additional energy consumption would be offset. If this advantage is large enough, industrial CHPs may become an attractive option for CO₂ capture and storage CCS. We therefore investigated the techno-economic performance of post-combustion CO₂ capture from small-to-medium-scale (50–200 MWe maximum electrical capacity) industrial Natural Gas Combined Cycle- (NGCC-) CHPs in comparison with large-scale (400 MWe) NGCCs in the short term (2010) and the mid-term future (2020–2025). The analyzed system encompasses NGCC, CO₂ capture, compression, and branch CO₂ pipeline.The technical results showed that CO₂ capture energy requirement for industrial NGCC-CHPs is significantly lower than that for 400 MWe NGCCs: up to 16% in the short term and up to 12% in the mid-term future. The economic results showed that at low heat-to-power ratio operations, CO₂ capture from industrial NGCC-CHPs at 100 MWe in the short term (41–44 €/tCO₂ avoided) and 200 MWe in the mid-term future (33–36 €/tCO₂ avoided) may compete with 400 MWe NGCCs (46–50 €/tCO₂ avoided short term, 30–35 €/tCO₂ avoided mid-term).     

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.     

The modelling of a hybrid combined cycle with pressurised fluidised bed combustion and CO2 capture

This study investigates the possibility of capturing CO₂ from flue gas under pressurised conditions, which could prove to be beneficial in comparison to working under atmospheric conditions. Simulations of two hybrid combined cycles with pressurised fluidised bed combustion and CO₂ capture are presented. CO₂ is captured from pressurised flue gas by means of chemical absorption after the boiler but before expansion. The results show a CO₂ capture penalty of approximately 8 percentage points (including 90% CO₂ capture rate and compression to 110 bar), which makes the efficiency for the best performing cycle 43.9%. It is 5.2 percentage points higher than the most probable alternative, i.e. using a natural gas fired combined cycle and a pulverised coal fired condensing plant separately with the same fuel split ratio. The largest part of the penalty is associated with the lower mass flow of flue gas after CO₂ capture, which leads to a decrease in work output in the expander and potential for feed water heating. The penalty caused by the regeneration of absorbent is quite low, since the high pressure permits the use of potassium carbonate, which requires less regeneration heat than for example the more commonly proposed monoethanolamine. Although the efficiencies of the cycles look promising it will be important to perform a cost estimate to be able to make a fair comparison with other systems. Such a cost estimate has not been done in this study. A significant drawback of these hybrid cycles in that respect is the complex nature of the systems that will have a negative effect on the economy.     

Integration of post-combustion capture and storage into a pulverized coal-fired power plant

Post-combustion CO₂ capture and storage (CCS) presents a promising strategy to capture, compress, transport and store CO₂ from a high volume–low pressure flue gas stream emitted from a fossil fuel-fired power plant. This work undertakes the simulation of CO₂ capture and compression integration into an 800 MW_e supercritical coal-fired power plant using chemical process simulators. The focus is not only on the simulation of full load of flue gas stream into the CO₂ capture and compression, but also, on the impact of a partial load. The result reveals that the energy penalty of a low capture efficiency, for example, at 50% capture efficiency with 10% flue gas load is higher than for 90% flue gas load at the equivalent capture efficiency by about 440 kWh_e/tonne CO₂. The study also addresses the effect of CO₂ capture performance by different coal ranks. It is found that lignite pulverized coal (PC)-fired power plant has a higher energy requirement than subbituminous and bituminous PC-fired power plants by 40.1 and 98.6 MW_e, respectively. In addition to the investigation of energy requirement, other significant parameters including energy penalty, plant efficiency, amine flow rate and extracted steam flow rate, are also presented. The study reveals that operating at partial load, for example at half load with 90% CO₂ capture efficiency, as compared with full load, reduces the energy penalty, plant efficiency drop, amine flow rate and extracted steam flow rate by 9.9%, 24.4%, 50.0% and 49.9%, respectively. In addition, the effect of steam extracted from different locations from a series of steam turbine with the objective to achieve the lowest possible energy penalty is evaluated. The simulation shows that a low extracted steam pressure from a series of steam turbines, for example at 300 kPa, minimizes the energy penalty by up to 25.3%.     

Ionic liquids for post-combustion CO2 absorption

The present work is a study to evaluate ionic liquids as a potential solvent for post-combustion CO₂ capture. In order to enhance the absorption performance of a CO₂ capture unit, different ionic liquids have been designed and tested. The main goal was to get a comparison between a reference liquid and selected ionic liquids. As the reference, a solution of 30 w% monoethanolamine (MEA) and water was used. A large range of different pure and diluted ionic liquids was tested with a special screening process to gain general information about the CO₂ absorption performance. Based on these results, a 60 w% ionic liquid solution in water was selected and the vapour–liquid equilibrium was measured experimentally between 40 °C and 110 °C. From these curves the enthalpy of absorption for capturing CO₂ into the ionic liquid was determined. With these important parameters one is able to calculate the total energy demand for stripping of CO₂ from the loaded solvent for comparison of the ionic liquid based solvent with the reference MEA solvent. The energy demand of this 60 w% ionic liquid is slightly lower than that of the reference solution, resulting in possible energy savings between 12 and 16%.     

Life cycle assessment of carbon dioxide capture and storage from lignite power plants

In this article, we present a life cycle assessment (LCA) of CO₂ capture and storage (CCS) for several lignite power plant technologies. The LCA includes post-combustion, pre-combustion and oxyfuel capture processes as well as subsequent pipeline transport and storage of the separated CO₂ in a depleted gas field.The results show an increase in cumulative energy demand and a substantial decrease in greenhouse gas (GHG) emissions for all CO₂ capture approaches in comparison with power plants without CCS, assuming negligible leakage within the time horizon under consideration. Leakage will, however, not be zero. Due to the energy penalty, CCS leads to additional production of CO₂. However, the CO₂ emissions occur at a much lower rate and are significantly delayed, thus leading to different, and most likely smaller, impacts compared to the no-sequestration case. In addition, a certain share of the CO₂ will be captured permanently due to chemical reactions and physical trapping.For other environmental impact categories, the results depend strongly on the chosen technology and the details of the process. The post-combustion approach, which is closest to commercial application, leads to sharp increases in many categories of impacts, with the impacts in only one category, acidification, reduced. In comparison with a conventional power plant, the pre-combustion approach results in decreased impact in all categories. This is mainly due to the different power generation process (IGCC) which is coupled with the pre-combustion technology.In the case of the oxyfuel approach, the outcome of the LCA depends highly on two uncertain parameters: the energy demand for air separation and the feasibility of co-capture of pollutants other than CO₂. If co-capture were possible, oxyfuel could lead to a near-zero emission power plant.     

Hollow fiber membrane separation process in the presence of gaseous and particle impurities for post-combustion CO2 capture

The membrane separation process for CO₂ capture can be interfered by the gaseous components and the fine particles in flue gas, especially in desulfurized flue gas. In this work, the pint-sized Polyimide(PI) hollow fiber membrane contactors were self-packed to investigate the membrane CO₂ separation from flue gas containing fine particles and gaseous contaminants (SO₂,SO₃,H₂O). First, the effects of SO₂, SO₃, water vapor, and gypsum particles on the CO₂ capture were studied independently and synergistically. The results showed that the effect of SO₂ on the membrane separation properties is indistinctive; however, the membrane performance was damaged seriously with the addition of SO₃. The high humidity promoted the CO₂ separation initially before inhibiting the PI membrane performance. Moreover, the decrease of the CO₂/N₂ selectivity and the permeation rate were accelerated with the coexistence of SO₂. The membrane performance showed an obvious deterioration in the presence of gypsum particles, with a 21% decrease in the CO₂/N₂ selectivity and 51% decrease in the permeation rate. Furthermore, the gypsum particles exerted dramatic damage. Under the WFGD conditions, the combined effects of SO₂, water vapor, and the gypsum particles influenced the stability of the membrane significantly. This tendency is mainly attributed to the deposition of fine particles and aerosol on the membrane surface, which occupied the effective area and enhanced the mass transfer resistance. This study of impurities’ influence could play an important role in further industrial application of membrane CO₂ capture.     

Integration and evaluation of a power plant with a CaO-based CO2 capture system

This paper explores the integration and evaluation of a power plant with a CaO-based CO₂ capture system. There is a great amount of recoverable heat in the CaO-based CO₂ capture process. Five cases for the possible integration of a 600 MW power plant with CaO-based CO₂ capture process are considered in this paper. When the system is configured so that recovered heat is used to replace part of the boiler heat load (Case 2), modelling not only shows that this is the system recovering the most heat of 1008.8 MW but also results in the system with the lowest net power output of 446 MW and the second lowest of efficiency of 34.1%. It is indicated that system performance depends both on the amount of heat recovery and the type of heat utilization. When the system is configured so that a 400 MW power plant is built using the recovered heat (Case 4), modelling shows that this is the system with the most net power output of 846 MW, the highest efficiency of 36.8%, the lowest cost of electricity of 54.3 €/MWh and the lowest cost of CO₂ avoided of 28.9 €/tCO₂. This new built steam cycle will not affect the operation of the reference plant which vents its CO₂ to the atmosphere, highly reducing the connection between the CO₂ capture process and the reference plant which vents its CO₂ to the atmosphere. The average cost of electricity and the cost of CO₂ avoided of the five cases are about 58.9 €/kWh and 35.9 €/tCO₂, respectively.     

Design and off-design analyses of a pre-combustion CO2 capture process in a natural gas combined cycle power plant

In this study, a cycle designed for capturing the greenhouse gas CO₂ in a natural gas combined cycle power plant has been analyzed. The process is a pre-combustion CO₂ capture cycle utilizing reforming of natural gas and removal of the carbon in the fuel prior to combustion in the gas turbine. The power cycle consists of a H₂-fired gas turbine and a triple pressure steam cycle. Nitrogen is used as fuel diluent and steam is injected into the flame for additional NO_x control. The heat recovery steam generator includes pre-heating for the various process streams. The pre-combustion cycle consists of an air-blown auto-thermal reformer, water–gas shift reactors, an amine absorption system to separate out the CO₂, as well as a CO₂ compression block. Included in the thermodynamic analysis are design calculations, as well as steady-state off-design calculations. Even though the aim is to operate a plant, as the one in this study, at full load there is also a need to be able to operate at part load, meaning off-design analysis is important. A reference case which excludes the pre-combustion cycle and only consists of the power cycle without CO₂ capture was analyzed at both design and off-design conditions for comparison. A high degree of process integration is present in the cycle studied. This can be advantageous from an efficiency stand-point but the complexity of the plant increases. The part load calculations is one way of investigating how flexible the plant is to off-design conditions. In the analysis performed, part load behavior is rather good with efficiency reductions from base load operation comparable to the reference combined cycle plant.     

Modeling CO2 capture with aqueous monoethanolamine

Hilliard completed several thermodynamic models in Aspen Plus^® for modeling CO₂ removal with amine solvents, including MEA–H₂O–CO₂. This solvent was selected to make a system model for CO₂ removal by absorption/stripping. Both the absorber and the stripper used RateSep? to rigorously calculate mass transfer rates. The accuracy of the new model was assessed using a recent pilot plant run with 35 wt.% (9 m) MEA. Absorber loading and removal were predicted within 6%, and the temperature profile was approached within 5 °C. An average 3.8% difference between measured and calculated values was achieved in the stripper. A three-stage flash configuration which efficiently utilizes solar energy was developed. It reduces energy use by 6% relative to a simple stripper. Intercooling was used to reach 90% removal in the absorber at these optimized conditions.     

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.     

A qualitative reliability and operability analysis of an integrated reforming combined cycle plant with CO2 capture

Most of the current CO₂ capture technologies are associated with large energy penalties that reduce their economic viability. Efficiency has therefore become the most important issue when designing and selecting power plants with CO₂ capture. Other aspects, like reliability and operability, have been given less importance, if any at all, in the literature.This article deals with qualitative reliability and operability analyses of an integrated reforming combined cycle concept. The plant reforms natural gas into a syngas, the carbon is separated out as CO₂ after a water-gas shift section, and the hydrogen-rich fuel is used for a gas turbine. The qualitative reliability analysis in the article consists of a functional analysis followed by a failure mode, effects, and criticality analysis (FMECA). The operability analysis introduces the comparative complexity indicator (CCI) concept.Functional analysis and FMECA are important steps in a system reliability analysis, as they can serve as a platform and basis for further analysis. Also, the results from the FMECA can be interesting for determining how the failures propagate through the system and their effects on the operation of the process. The CCI is a helpful tool in choosing the level of integration and to investigate whether or not to include a certain process feature. Incorporating the analytical approach presented in the article during the design stage of a plant can be advantageous for the overall plant performance.     

Co-production of hydrogen and electricity with CO2 capture

Electricity and hydrogen can be used as energy carriers to reduce emissions of CO₂ from small and mobile energy users. One of the most promising technologies for the production of electricity and hydrogen with low CO₂ emissions is coal gasification with CO₂ capture and storage. Performance and cost data are presented for plants which produce electricity and hydrogen alone and plants which co-produce both of these energy carriers. The co-production plants include plants which produce a fixed ratio of hydrogen to electricity and plants which are able to vary the ratio while continuing to operate the gasification and CO₂ capture parts of the plant at full load. The paper also assesses the ability of these types of plants to satisfy the varying demands for hydrogen and electricity in future energy supply systems. The lowest cost option for the scenarios assessed in the paper is the use of flexible co-production plants with underground buffer storage of hydrogen.     

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.     

Comparative study of the heats of absorption of post-combustion CO2 absorbents

Heats of absorption of CO₂ with different solvents were measured in this work in a commercially available reaction calorimeter CPA-122 (Chemisens AS, Sweden) as function of temperature, loading and solvent composition over the temperature range from 40 to 120 °C. Studied amines include primary amines (monoethanolamine and 2-amino-2-methyl-1-propanol), tertiary amines (N-methyldiethanolamine and N,N-diethylethanolamine), diamines (1-(2-aminoethyl)-aminoethanol and N-methyl-1,3-propanediamine), triamine (diethylenetriamine), and cyclic amine (piperazine). Combinations of these amines and also mixtures of potassium carbonate and piperazine were tested. Experimental heats of absorption of CO₂ with these systems are compared.     

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.