Long-term coal gasification-based power with near-zero emissions. Part B: Zecomag and oxy-fuel IGCC cycles

In this second part of the work, two other long-term technologies for power generation from coal are investigated. The Zecomag plant has the same syngas production system of the Zecomix plant, described in the first part of this paper, but hydrogen-rich syngas is here burned with air in an open-cycle gas turbine. The aim is a simplification of the power island, more similar to a combined cycle; however, CO₂ capture falls from 100% to about 90% and NO_x emissions are present.An advanced oxy-fuel IGCC is the second plant investigated in this paper, presenting the same zero-emission potential of Zecomix. Syngas is produced in a high pressure, dry feed, oxygen blown gasifier and cleaned in a hot-gas-clean-up system. Clean syngas is then burned with oxygen and expanded in a turbine, using compressed recirculated CO₂ to moderate firing temperature and to cool turbine blades.The loss of net efficiency, with respect to Zecomix, is very limited (1–2 points) with both configurations. In order to better evaluate the performances obtained, a comparison with reference state-of-the art IGCCs and a long-term IGCC without CO₂ capture is also presented.     

Conceptual design of a three fluidised beds combustion system capturing CO2 with CaO

In this work, the Aspen Hysys conceptual design of a new process for energy generation at large scale with implicit CO₂ capture is presented. This process makes use of the CaO capability for CO₂ capture at high temperature and the possibility of regenerating this sorbent working in interconnected fluidised bed reactors operating at different temperatures. The proposed process has the advantage of producing power with minimum CO₂ emissions and very low energy penalties compared with similar air-based combustion power plants. In this system, five main parts can be distinguished: the combustor where coal is burnt with air, the calciner where the fresh and the recycled CaCO₃ is calcined, the carbonator where the CO₂ produced in the combustor is captured, the supercritical steam cycle and the CO₂ compression system. In this arrangement, the three fluidised bed reactors are interconnected in such a way that it is possible to perform the CaCO₃ calcination at a temperature of 950 °C with the energy transported by a hot solid stream produced in the circulating fluidised bed combustor operating at 1030 °C. The stream rich in CaO produced in the calciner is split into three parts. One of them is transported to the carbonator operating at 650 °C where most of the CO₂ in the flue gas produced in the combustor is captured. The second one is sent to the combustor, where it is heated up and used as energy carrier. The third solid stream that leaves the calciner is a purge in order to maintain the capture system activity and to avoid inert material accumulation. Because of the high temperatures involved in all the system, it is possible to recover most of the energy in the fuel and to produce power in a supercritical steam cycle. A case study is presented and it is demonstrated that under these operating conditions, 90% CO₂ capture efficiency can be achieved with no energy penalty further than the one originated in the CO₂ compression system.     

Designing a supercritical steam cycle to integrate the energy requirements of CO2 amine scrubbing

Absorption by chemical solvents combined with CO₂ long-term storage appears to offer interesting and commercial applicable CO₂ capture technology. However one of the main disadvantages is related to the large quantities of heat required to regenerate the amine solvent that means an important power plant efficiency penalty. Different studies have analyzed alternatives to reduce the heat duty on the reboiler and the thermal integration requirements on existing power cycles. In these studies integration principles have been well set up, but there is a lack of information about how to achieve an integrated design and the thermal balances of the modified cycle flowsheet. This paper proposes and provides details about a set of modifications of a supercritical steam cycle to overcome the energy requirements through energetic integration with the aim of reducing the efficiency and power output penalty associated with CO₂ capture process. Modifications include a new designed low-pressure heater flowsheet to take advantage of the CO₂ compression cooling for postcombustion systems and integration of amine reboiler into a steam cycle. It has been carried out several simulations in order to obtain power plant performance depending on sorbent regeneration requirements.     

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.     

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.     

Exergy analysis as a tool for the integration of very complex energy systems: The case of carbonation/calcination CO2 systems in existing coal power plants

A common characteristic of carbon capture and storage systems is the important energy consumption associated with the CO₂ capture process. This important drawback can be solved with the analysis, synthesis and optimization of this type of energy systems. The second law of thermodynamics has proved to be an essential tool in power and chemical plant optimization. The exergy analysis method has demonstrated good results in the synthesis of complex systems and efficiency improvements in energy applications.In this paper, a synthesis of pinch analysis and second law analysis is used to show the optimum window design of the integration of a calcium looping cycle into an existing coal power plant for CO₂ capture. Results demonstrate that exergy analysis is an essential aid to reduce energy penalties in CO₂ capture energy systems. In particular, for the case of carbonation/calcination CO₂ systems integrated in existing coal power plants, almost 40% of the additional exergy consumption is available in the form of heat. Accordingly, the efficiency of the capture cycle depends strongly on the possibility of using this heat to produce extra steam (live, reheat and medium pressure) to generate extra power at steam turbine. The synthesis of pinch and second law analysis could reduce the additional coal consumption due to CO₂ capture 2.5 times, from 217 to 85 MW.     

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.     

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.     

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%.     

Chemical looping combustion for power generation—Concept study for a 10 MWth demonstration plant

A semi-commercial 10 MW_th chemical looping combustion (CLC) plant for power production is proposed as a next scale demonstration plant after successful operation of a 120 kW CLC pilot rig. The design criteria for the CLC boiler are derived from the experience obtained from the CLC pilot rig at Vienna University of Technology. The IPSEpro simulation environment is chosen for implementation of the process flow sheet of the CLC power plant. A single pressure steam cycle is suggested for this small scale demonstration plant. Heat exchangers and a five-stage steam turbine are arranged. Basic design parameters of the power plant are derived from detailed mass and energy investigations and discussed. It turns out that the net electric efficiency of such a small scale plant can be expected to be in the range of 32.5–35.8%. However, a demonstration of CLC at such a scale is necessary in order to gain confidence in more sophisticated CLC power generation concepts at larger scale.     

Multi-stage chemical looping combustion (CLC) for combined cycles with CO2 capture

This paper presents application of the chemical looping combustion (CLC) method in natural gas-fired combined cycles for power generation with CO₂ capture. A CLC combined cycle consisting of single CLC-reactor system, an air turbine, a CO₂-turbine and a steam cycle has been designated as the base-case cycle. The base-case cycle can achieve net plant efficiency of about 52% at an oxidation temperature of 1200 °C. In order to achieve a reasonable efficiency at lower oxidation temperatures, reheat is introduced into the air turbine by employing multi CLC-reactors. The results show that the single reheat CLC-combined cycle can achieve net plant efficiency of above 51% at oxidation temperature of 1000 °C and above 53% at the oxidation temperature of 1200 °C including CO₂ compression to 110 bar. The double reheat cycle results in marginal efficiency improvement as compared to the single reheat cycle. The CLC-cycles are also compared with a conventional combined cycle with and without post-combustion capture in amine solution. All the CLC-cycles show higher net plant efficiencies with close to 100% CO₂ capture as compared to a conventional combined cycle with post-combustion capture, which is very promising.     

Carbon dioxide capture from combustion flue gases with a calcium oxide chemical loop. Experimental results and process development

Post-combustion carbonate looping processes are based on the capture of carbon dioxide from the flue gases of an existing power plant in a circulating fluidized bed reactor (CFB) of calcium oxide (the carbonator) particles. The calcination of calcium carbonate in a new oxy-fired CFBC power plant regenerates the sorbent (calcium oxide particles) and obtains high purity carbon dioxide. This communication presents experimental results from a small test facility (30 kWt) operated in continuous mode using two interconnected CFB reactors as carbonator and calciner. Capture efficiencies between 70 and 97% have been obtained under realistic flue gas conditions in the carbonator reactor (temperatures around 650 °C). The similarity between process conditions and those existing in CFBC power plants should allow a rapid scaling up of this technology. The next steps for this process development are also outlined.     

Effect of steam hydration on performance of lime sorbent for CO2 capture

Lime is considered a feasible sorbent for the capture of CO₂ from large stationary sources. The positive attributes of a natural source material, low cost and lack of harmful by-products are offset by rapid deterioration in performance and high regeneration temperature. Performance can be improved by hydrating the lime using steam. We investigate a steam hydration process wherein lime is hydrated for 5 min at 300 °C and atmospheric pressure in a mixture of steam and CO₂. The experiments consisted of 10 capture cycles with 60% of the lime active at the end. Extrapolation using a decay model suggests a residual carbonation level of 48%, significantly higher than the 8% achieved by dry lime cycles. The cost of replacement sorbent under these conditions is less than $1/t of CO₂ captured. The hydrated lime process also reduces the thermal load, for heating and cooling, by half as well as the inventory, and therefore solids handling, by a factor 5 over dry lime. The introduction of the hydration reaction provides another exothermic reaction for heat management.     

Experimental validation of in situ CO2 capture with CaO during the low temperature combustion of biomass in a fluidized bed reactor

A novel concept for capturing CO₂ from biomass combustion using CaO as an active solid sorbent of CO₂ is discussed and experimentally tested. According to the CaO/CaCO₃ equilibrium, if a fuel could be burned at a sufficiently low temperature (below 700 °C) it would be possible to capture CO₂ “in situ” with the CaO particles at atmospheric pressure. A subsequent step involving the regeneration of CaCO₃ in a calciner operating at typical conditions of oxyfired-circulating fluidized combustion would deliver the CO₂ ready for purification, compression and permanent geological storage. Several series of experiments to prove this concept have been conducted in a 30 kW interconnected fluidized bed test facility at INCAR-CSIC, made up of two interconnected circulating fluidized bed reactors, one acting as biomass combustor-carbonator and the other as air-fired calciner (which is considered to yield similar sorbent properties than those of an oxyfired calciner). CO₂ capture efficiencies in dynamic tests in the combustor-carbonator reactor were measured over a wide range of operating conditions, including different superficial gas velocities, solids circulation rates, excess air above stoichiometric, and biomass type (olive pits, saw dust and pellets). Biomass combustion in air is effective at temperatures even below the 700 °C, necessary for the effective capture of CO₂ by carbonation of CaO. Overall CO₂ capture efficiencies in the combustor-carbonator higher than 70% can be achieved with sufficiently high solids circulation rates of CaO and solids inventories. The application of a simple reactor model for the combined combustion and CO₂ capture reactions allows an efficiency factor to be obtained from the dynamic experimental test that could be valuable for scaling up purposes.     

Performance of oil palm kernel shell gasification using a medium-scale downdraft gasifier

This article focused on the performance of oil palm kernel shell (PKS) gasification using a medium-scale downdraft gasifier with a feedstock capacity of 500 kg at a temperature range of 399–700°C and at a feed rate of 177 kg/h. This article is important for evaluating the reliability of PKS gasification for commercial power generation activities from biomass. The process performance was evaluated based on the syngas calorific value (CV), syngas flow rate, and its cold gas efficiency (CGE). The syngas flow rates and CVs were measured using a gas flow meter and a gas analyzer in real time. The data obtained were then analyzed to evaluate the performance of the process. The results showed that the CGE of the process was moderately high (51%) at 681°C, with a high syngas CV (4.45–4.89 MJ/Nm³) which was ideal for gas engine applications. The PKS gasification performance increased when the reactor temperature increased. Projections were made for the CGE and the syngas CV for the PKS gasification with increased reactor temperatures and it was found that these values could be increased up to 80% and 5.2 MJ/Nm^3, respectively at a reactor temperature of 900°C. In addition, the estimated power that could be generated was about 600 kW_e at a maximum operation of 500 kg/h of feed rate. Based on the analysis, a medium-scale PKS gasification is observed to be a promising process for power generation from biomass due to the favorable performance of the process.     

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.     

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.     

Testing of hydrotalcite-based sorbents for CO2 and H2S capture for use in sorption enhanced water gas shift

The feasibility of the sorption enhanced water gas shift (SEWGS) process under sour conditions is shown. The sour-SEWGS process constitutes a second generation pre-combustion carbon capture technology for the application in an IGCC. As a first critical step, the suitability of a K₂CO₃ promoted hydrotalcite-based CO₂ sorbent is demonstrated by means of adsorption and regeneration experiments in the presence of 2000 ppm H₂S. In multiple cycle experiments at 400 °C and 5 bar, the sorbent displays reversible co-adsorption of CO₂ and H₂S. The CO₂ sorption capacity is not significantly affected compared to sulphur-free conditions. A mechanistic model assuming two different sites for H₂S interaction explains qualitatively the interactions of CO₂ and H₂S with the sorbent. On the type A sites, CO₂ and H₂S display competitive sorption where CO₂ is favoured. The type B sites only allow H₂S uptake and may involve the formation of metal sulphides. This material behaviour means that the sour-SEWGS process likely eliminates CO₂ and H₂S simultaneously from the syngas and that an almost CO₂ and H₂S-free H₂ stream and a CO₂ + H₂S stream can be produced.     

Tandem bed configuration for sorption-enhanced steam reforming of methane

The required properties of a CO₂ sorbent for sorption-enhanced steam–methane reforming (SESMR) are derived following a top-down approach. First the required CO₂ equilibrium pressure of the sorbent is derived from system restraints, then a suitable sorbent is searched for matching the required CO₂ pressure. The selected material, barium orthotitanate Ba₂TiO₄, has been characterized and tested on lab-scale. From this follows that the capacity and kinetics are poor compared with CaO, which has been investigated for SESMR. The best use of Ba₂TiO₄ is in combination with CaO, making use of the good properties of both: the high capacity and good kinetics of CaO, and the low CO₂ equilibrium pressure of Ba₂TiO₄ allowing high CH₄ conversion at relatively low steam-to-methane ratios (3–4).     

Combined steam-dry reforming of toluene in syngas over CaNiRu/Al2O3 catalysts

Cracking, steam reforming, dry reforming, and combined steam and dry reforming of toluene in model syngas were performed using catalysts to simulate tar removal produced during biomass gasification. The catalysts were prepared by adding Ru, Ca, and Mn to Ni-based catalysts, and their properties were measured using BET, pulse CO chemisorption, XRD and TG. In steam and dry reforming of toluene, a high toluene conversion was observed with increasing Ca content in the catalyst and catalysts containing Ca showed a higher activity than those containing Mn. In combined steam-dry reforming with syngas, 1%CaNiRu/Al₂O₃ indicated a conversion of 93.9% at 800°C.