The conventional techniques, which are being used to clean the flue gases such as catalytic reduction method for NO removal, wet and dry scrubbers for SO 2 removal and ESP for particulate removal, are becoming more expensive and less suitable for small plants and mobile emission sources. Non-thermal plasma (NTP) techniques utilizing electrical discharges give an innovative approach for economical solution of gas cleaning. The studies present recent work on applying the electrical discharge plasma technology for treating gaseous pollutants, in general, and nitric oxide, in particular, as this is one of the major contributors to air pollution. The present works focuses attention on dielectric barrier discharge technique for nitric oxide removal from simulated gas compositions and investigate the effect of various operating parameters on the NO removal efficiencies at room temperature. The effects of various parameters, viz. discharge power, gas velocity, initial NO concentration (ppm), gas mixture composition, etc., on NO removal efficiency are discussed. Studies are divided into two parts: in the nitrogen atmosphere and argon atmosphere respectively, in order to investigate the effect of various operating parameters on the NO removal efficiencies at room temperature. The results in nitrogen atmosphere indicate that the influence of the discharge power, oxygen content and different initial concentration on NO removal efficiency are also studied. Conclusion that increasing discharge power is in favor of the NO removal. Adding oxygen reduce the NO removal efficiency significantly, and changing the NO initial concentration effected on NO removal efficiency but nor as good as the factors of discharge power, oxygen content. In the argon atmosphere, the dielectric barrier discharge require lower voltage level. The effect of the discharge power, gas velocity and oxygen content on NO removal efficiencies are studied and some conclusions be obtained, increasing discharge power and lowing flue gas velocity would conducive to removal, adding oxygen would hinder the removal of NO. Further result and comparative study of various cases be presented in this paper.

This paper mainly seeks to explore and answer some questions for desulfurization and denitration in thermal power plants in China. Firstly, the desulfurization and denitration technology applicated in the power plant in China at present were analyzed. It is considered that taken combination of the existed technique for purified the pollutants from the thermal power plants, not only lead to the wastage of huge amount of investment, increasing of operating costs, decreasing of the economic benefits, but also add an additional area. It is necessary to develop the integration technology of desulfurization and denitration simultaneously. Secondly the integration technology of desulfurization and denitration at present in China was briefly reviewed such as activated carbon adsorption, SNRB, etc. and most of those at a research stage include the plasma technology. In the third of the paper, the non-thermal plasma technology i.e electron-beam technique, corona discharge and dielectric barrier discharge were discussed. Finally, combined with the actual situation in China, the application prospects of the desulfurization and denitration technology using plasma discharge in the flue gas was bring up. The article also pointed out the barriers need to be overcome if the technology will be applied in power plant, as well as the development direction of desulfurization and denitration technology from flue gas in power plant in China.

Coal consumption for electricity generation produces over 30% of U.S. carbon dioxide (CO 2 ) emissions, but coal is also an available, secure, and low cost fuel that is currently utilized to meet roughly half of America’s electricity demand. While the world transitions from the existing fossil fuel-based energy infrastructure to a sustainable energy system, carbon dioxide capture and sequestration (CCS) will be a critical technology that will allow continued use of coal in an environmentally acceptable manner. Techno-economic analyses are useful in understanding the costs and benefits of CCS. However, typical techno-economic analyses of post-combustion CO 2 capture systems assume continuous operation at a high CO 2 removal, which could use 30% of pre-capture electricity output and require new capacity installation to replace the output lost to CO 2 capture energy requirements. This study, however, considers the inherent flexibility in post-combustion CO 2 capture systems by modeling power plants that vary CO 2 capture energy requirements in order to increase electricity output when economical under electricity market conditions. A first-order model of electricity dispatch and a competitive electricity market is used to investigate flexible CO 2 capture in response to hourly electricity demand variations. The Electric Reliability Council of Texas (ERCOT) electric grid is used as a case study to compare plant and grid performance, economics, and CO 2 emissions in scenarios without CO 2 capture to those with flexible or inflexible CO 2 capture systems. Flexible CO 2 capture systems can choose how much CO 2 to capture based on the competition between CO 2 and electricity prices and a desire to either minimize operating costs or maximize operating profits. Coal and natural gas prices have varying degrees of predictability and volatility, and the relative prices of these fuels have a major impact on power plant operating costs and the resulting plant dispatch sequence. Because the chosen operating point in a flexible CO 2 capture system affects net power plant efficiency, fuel prices also influence which CO 2 capture operating point may be the most economical and the resulting dispatch of power plants with CO 2 capture. Several coal and natural gas price combinations are investigated to determine their impact on flexible CO 2 capture operation and the resulting economic and environmental impacts at the power plant and electric grid levels. This study investigates the costs and benefits of flexible CO 2 capture in a framework of a carbon-constrained future where the effects of major energy infrastructure changes on fuel prices are not entirely clear.

Carbon capture and storage (CCS) is often identified as an important technology for mitigating global carbon dioxide (CO 2 ) emissions. For example, the IEA currently suggests that 160GW of CCS may need to be installed globally by 2030 as part of action to limit greenhouse gas concentrations to 550ppm-CO 2 eq, with a further 190GW CCS capacity required if a 450ppm-CO 2 eq target is to be achieved. Since global rollout of proven CCS technologies is not expected to commence until 2020 at the earliest this represents a very challenging build rate. In these circumstances retrofitting CO 2 capture to existing plants, probably particularly post-combustion capture on pulverized coal-fired plants, could play an important role in the deployment of CCS as a global strategy for implementing CO 2 emissions reductions. Retrofitting obviously reduces the construction activity required for CCS deployment, since fewer additional new power plants are required. Retrofitting CCS to an existing fleet is also an effective way to significantly reduce CO 2 emissions from this sector of the electricity generation mix; it is obviously not possible to effect an absolute reduction in coal power sector CO 2 emissions simply by adding new plants with CCS to the existing fleet. Although it has been proposed that plants constructed now and in the future can be ‘capture ready’, much of the existing fleet will not have been designed to be suitable for retrofit of CO 2 capture. Some particular challenges that may be faced by utilities and investors considering a retrofit project are discussed. Since it is expected that post-combustion capture retrofits to pulverized coal plants will be the most widely applied option for retrofit to the existing fleet (probably regardless of whether base plants were designed to be capture ready or not), a review of the technical and potential economic performance of this option is presented. Power cycle performance penalties when capture is retrofitted need to be addressed, but satisfactory options appear to exist. It also seems likely that the economic performance of post-combustion capture retrofit could be competitive when compared to other options requiring more significant capital expenditure. Further work is, however, required both to develop a generally accepted methodology for assessing retrofit economics (including consideration of the implications of lost output after retrofit under different electricity selling price assumptions) and to apply general technical principles to case studies where site-specific constraints are considered in detail. The overall conclusion from the screening-level analysis reported in this paper is that, depending on project-specific and market-specific conditions, retrofit could be an attractive option, especially for fast track initial demonstration and deployment of CCS. Any unnecessary regulatory or funding barriers to retrofit of existing plants and to their effective operation with CCS should, therefore, be avoided.

This paper explains the system economics of an example integrated network that uses anthropogenic CO 2 from Texas Gulf Coast fossil power plants for enhanced oil recovery (EOR). These CO 2 sources and sinks are connected via a pipeline network. A discounted cash flow model indicates that for all candidate oil fields that require less than an estimated $10/BBL in EOR capital expenditure, all three entities (CO 2 capture, pipelines, and EOR operators) can have 20% internal rate of return at $55 per tonne of CO 2 and $56 per barrel of oil. These results include no existing or future tax incentives, and there are some costs not yet included. However, a Monte Carlo analysis shows insight by indicating that the total system rate of return is most sensitive to oil production parameters. Oil price and estimated amount of recoverable oil are the most positively influential factors while the EOR capital cost is the most negatively sensitive factor. The capital costs of capture and CO 2 price are less sensitive, both negatively affecting rate of return.

Oxy-fired combustion has been identified as a key technology needed for greenhouse gas mitigation because it is capable of producing a concentrated CO 2 stream suitable for sequestration. This technology as applied to pulverized coal systems has recently been brought to a near-commercial status with several key world-wide demonstrations. A barrier to its adoption has been the large additional auxiliary power required for oxygen production and CO 2 compression which results in low overall system efficiency. There have been various strategies proposed to address these efficiency issues. A very promising concept is the use of pressurized combustion in order to increase the system efficiency. The use of pressure increases the power requirement of the air separation system. However, pressurization increases the boiler and steam side efficiencies while decreasing the power requirement for the CO 2 compression system. The use of pressure will also affect the performance and size of each piece of equipment within the system. This paper describes the efficiency benefit of using pressure as compared with a baseline ambient pressure oxy-fired system and a typical air-fired system. The technical aspects of various system layouts are presented, the overall efficiency is evaluated and the merits of specific configurations are discussed. Design issues of equipment associated with the fuel supply, furnace, ash removal, heat transfer and flame moderation systems are presented.

The present study attempts to take nitric acid as absorbent to clean up SO 2 and NO gases simultaneously from the simulated flue gas in the lab-scale bubbling reactor, this study was divide into the individual DeNOx experiments and the combined DeSOx/DeNOx experiments: the individual DeNOx experiments were carried out to examine the effect of various operating parameters such as input NO concentration, nitric acid concentration, oxygen concentration input SO 2 concentration, adding KMnO 4 as additive and taking NaOH as the secondary absorption processes on the SO 2 and NOx removal efficiencies at room temperature, the results of the individual DeNOx show that NO removal efficiency of 70%–95% were achieved under optimized conditions. NO removal efficiency increased with the increasing nitric acid concentration and increased by adding KMnO 4 into the absorbent as additive as well. The removal efficiency of NO can reach 95% when using the two-step integrated processes of (HNO 3 +KMnO 4 )-NaOH, the absorption solution of 50% nitric acid, 400ppm of input NO concentration. 0.5% oxygen concentration and without SO 2 in the simulated flue gas. No improvement on the NO x removal efficiency was observed with the increasing of KMnO 4 and NaOH concentration in the scrubbing solution. The results of the combined DeSOx/DeNOx experiments show that the maximum DeNOx and DeSOx efficiencies ranged from 36.6% to 81% and from 99.4% to 100.0%, respectively. The prime parameters affecting the NOx removal efficiency are the oxygen concentration and the input SO 2 concentration.

In this paper two methodologies, able to avoid CO 2 dispersion in atmosphere, have been analyzed: • treating exhaust gases in order to remove, liquefy and store the produced carbon dioxide; • de-carbonizing fossil fuels before using them in the combustion in order to inhibit completely carbon dioxide production. These methodologies have been implemented in advanced power plants based on gas turbine: a combined cycle power plant (CC), fed by natural gas, and an integrated gasification combined cycle (IGCC), fed by coal. The exhaust gas treatment is based on a chemical process of absorption, while the fossil fuel decarbonization is based on partial oxidation of methane, steam methane reforming and coal gasification. These systems require material and energetic integrations with the power sections and so the best interconnections must be investigated in order to obtain good overall performance. With reference to thermodynamic and economic performance, significant comparisons have been made between the above mentioned reference plants. An efficiency decrease and an increase in the cost of electricity have been obtained when power plants are equipped with systems able to reduce CO 2 emissions. However, in order to obtain low CO 2 emissions when coal is used, the coal decarbonization must be implemented: in this case it is possible to attain a global efficiency of about 38%, a specific emission of 0.1117 kg/kWh and an increase of kWh cost of about 32%. Vice versa, in order to obtain low CO 2 emissions when natural gas is used, the exhaust gas treatment must be implemented: in this case it is possible to attain a global efficiency of about 50.7%, a specific emission of 0.0391 kg/kWh and an increase of kWh cost of about 15%. The clean use of coal seems to have good potential because it allows low energy penalizations (about 7.5 percentage points) and economic increases of about 32%. Because of the great availability, the homogeneous distribution and the low cost of this fuel, these results seem to be very interesting especially in the viewpoint of a transition towards the “hydrogen economy”, based, at least in the medium term, on fossil fuels.

Anthropogenic carbon dioxide emission from its sources must be reduced to decrease the threat of global warming. Calcium oxide is considered as an effective carbon dioxide absorbent in biomass or coal gasification process as well as conventional power plants. It reacts with carbon dioxide to form calcium carbonate which can be decomposed into the original oxide and carbon dioxide at high temperature by calcination. In order to make this method practical for the carbon dioxide capture and sequestration, the performance of the calcium oxide absorbent must be maintained over a large number of carbonation/calcination cycles. For this reason, loss in the surface area of the absorbent due to pore plugging and sintering of particles in cyclic operation must be avoided. To prevent or minimize this problem, a simple and effective procedure for immobilization of calcium oxide on a fibrous alumina mat was developed in this study. The prepared samples were observed by SEM and the cyclic performance of the calcium oxide absorbent was evaluated by TGA experiments and compared to the previous studies in literature. 75% and 62% maximum carbonation conversions of the prepared absorbents with 23 wt % and 55 wt % calcium oxide content were achieved respectively and remained stable even after ten cycles whereas conversion in the literature data dropped steeply with the number of cycles.

This paper presents the process design and the energy analysis for a coal-fired power plant based on pressurised oxycoal combustion and including carbon capture technologies. A combustion technology performing a pressurised combustion of coal in an atmosphere of O 2 /CO 2 /H 2 O and including flue gases recycling has been selected. Combustion and steam production occur in separated equipments and the combustor’s design allows achieving high ash removal efficiency. The Rankine cycle has been chosen as the most viable thermodynamic cycle in a short-term scenario. Oxygen required by the combustion process is supplied by a cryogenic Air Separation Unit (ASU) and a double-reheat ultrasupercritical cycle is employed with main steam conditions of 250bar/605°C and reheat steam temperatures of 605°C/620°C. All choices related to thermal cycle selection and process design have been conducted upon the principle of feasibility and reliability. In order to increase net plant efficiency both sensible and latent heat is recovered from the flue gas stream before entering the purification and compression section. By operating in pressure it becomes possible to recover a larger amount of heat than in the atmospheric case. As a result, all low pressure steam bleedings and the corresponding regenerative heat exchangers can be eliminated. Process simulation is carried out in the paper and the expected efficiency is evaluated, as well as other cycle performance parameters. Since a relevant benefit may arise from the combustion of cheap coals, the impact of burning high-ash content and low ash-fusion-temperature coals is assessed. The impact of energy penalties associated to oxygen production and the benefit arising from high heat-transfer coefficients due to the increased pressure of the flue gas are deeply investigated.

A novel transcritical Rankine cycle is presented in this paper. This cycle adopts CO 2 as its working fluid, with exhaust from a gas turbine as its heat source and LNG as its cold sink. With CO 2 working transcritically, large temperature difference for the Rankine cycle is realized. Moreover, the CO 2 in the gas turbine exhaust is further cooled and liquefied by LNG after transferring heat to the Rankine cycle. In this way, not only the cold energy is utilized, but also a large part of the CO 2 from burning of the vaporized LNG is recovered. In this paper, the system performance of this transcritical cycle is calculated. The influences of the highest cycle temperature and pressure to system specific work, exergy efficiency and liquefied CO 2 mass flow rate are analyzed. The exergy loss in each of the heat exchangers is also discussed. It turns out that this kind of CO 2 cycle is energy-conservative and environment-friendly.