Bituminous Coal-fired Power Plant Research Articles

Discussion on the Life Cycle of Greenhouse Gas Emissions from the 2021 UNECE LCA Report and Korean LCI DB for Electricity Generation

Objectives : The greenhouse gas (GHG) emissions of coal, natural gas, wind, solar, hydropower, and nuclear electricity generation mentioned in the United Nations Economic Commission for Europe (UNECE) LCA report were discussed. Korean GHG emissions were calculated from the electricity database (DB) of the Korean national life cycle inventory (LCI), compared with the international average, and then discussed. The aim of this study was to discuss the necessity of updating and internationalizing the national LCI DB.Methods : The GHG emissions from the generation of coal power, natural gas power, wind power, onshore wind power, solar power, and hydropower in the UNECE LCA study were analyzed, and climate change, that is, GHG emissions, among the environmental impact assessment categories was discussed. The GHG emissions per 1 kWh functional unit were calculated from the electricity DB of the Korean national LCI by applying the global warming potential to GHGs.Results and Discussion : The GHG emissions from natural gas (452 g CO<sub>2</sub>-eq./kWh), nuclear (6.3 g CO<sub>2</sub>-eq./kWh), and solar power generation (53 g CO<sub>2</sub>-eq./kWh) presented in the national LCI DB were within the range of results presented in the UNECE LCA report. However, GHG emissions of Korean coal power generation exceeded the UNECE average and highest ranges. The GHG emissions of Korean hard coal and bituminous power generation were 1,351 g CO<sub>2</sub>-eq./kWh and 1,160 g CO<sub>2</sub>-eq./kWh, respectively, which were higher than the highest UNECE value, 1,095 g CO<sub>2</sub> eq./kWh (China). Analysis of the Korean electricity LCI DB for coal power plants showed that bituminous coal-fired power plants that use more brown coal, which is known to be relatively low-quality coal, produce less CO<sub>2</sub> than anthracite coal power plants. In Korean coal-fired power plants, it is necessary to check whether CO<sub>2</sub> generated from processes other than the combustion process is significant.Conclusion : Electricity accounts for the largest portion when calculating national greenhouse gas emissions, therefore, accurate data is necessary. Korea, which is highly dependent on coal-fired power generation for electricity production, should update its electricity LCI DB as soon as possible to increase national competitiveness and use it as a basis for realizing carbon neutrality by 2050.

Comparison of PMtotal, PM10, PM2.5, NOx, and SO2 Emission Factors from Coal-fired Power Plants per Load Change

For two bituminous coal-fired power plants with 500 MW and pulverized coal combustion type, the concentration of PMtotal, >PM10, PM2.5-10, PM2.5, NOx, and SO2 was measured, and their emission factors were calculated through field measurement. The measurement points started from the boiler downstream and continued to the air pollution control devices (APCDs) that are installed in series, namely, the selected catalytic reduction system (SCR), air preheater (APH), electrostatic precipitator (ESP) and wet flue gas desulfurization system (WFGD). The measurement was performed at one point for more than three times by using the Korean standard method for air pollutants. However, all measurement points, except for the stacks, were not representative of the standard test method. In addition, the PM concentration was too high to reduce the collection time due to isokinetic sampling. There is a limitation of how representative the measurement results can be. During the field measurement period, the power production rate of the two coal-fired power plants was 91.6% and 79.2% in the P-1 and P-2, respectively. Moreover, in the P-2, with a low power production rate, the concentration of PMtotal, PM10, PM2.5, and NOx was found to be low, and the emission factor calculated by dividing the measured concentration value by the fuel usage was also estimated to be low. Such results are due to the coal combustion chamber and various types of APCD being operated at a lower-load condition than the design capacity. In turn, the number of pollutants generated was less, and the removal efficiency of the pollutant became high. However, it was found that the concentration of SO2 generated and the emission factor are more significantly affected by the sulfur content of the coal than the load factor change. To this end, reducing the operation load of the coal-fired power plant improves the combustion efficiency and APCDs performance and decreases the emission factor, resulting in more reduction of the air pollutants than that based on the simple calculation.

The key roles of Fe-bearing minerals on arsenic capture and speciation transformation during high-As bituminous coal combustion: Experimental and theoretical investigations

The conversion of As vapor released from coal combustion to less hazardous solids is an important process to alleviate As pollution especially for high-As coal burning, but the roles of key ash components are still in debate. Here, we used multiple analytical methods across the micro to bulk scale and density functional theory to provide quantitative information on As speciation in fly ash and clarify the roles of ash components on As retention. Fly ash samples derived from the high-As bituminous coal-fired power plants showed a chemical composition of typical Class F fly ash. In-situ electron probe microanalysis (EPMA) was for the first time used to quantify and distinguish the inter-particle As distribution difference within coal fly ash. The spatial distribution of As was consistent with Fe, O, and sometimes with Ca. Grain-scale distribution of As in coal fly ash was quantified and As concentrations in single ash particles followed the order of Fe-oxides > aluminosilicates > unburned carbon > quartz. Sequential extraction and Wagner chemical plot of As confirmed that Fe minerals rather than Al-/Ca-bearing minerals played a vital role in capturing and oxidizing As3+ into solid phase (As5+). Magnetite content in fly ash well-correlated with the increase ratio of As before and after magnetic separation, suggesting magnetite enhanced As enrichment in fly ash. Density functional theory (DFT) indicated that the bridges O sites of octahedral structure on Fe3O4 (111) surface were likely strong active sites for As2O3 adsorption. This study highlights the importance of magnetite on As transformation during bituminous or high-rank coal combustion in power plants and has great implications for developing effective techniques for As removal.

Characteristic of mercury on the surface of ash originating from electrostatic precipitators of lignite and bituminous coal-fired power plants

Characteristic of mercury on the surface of ash originating from electrostatic precipitators of lignite and bituminous coal-fired power plants

Characteristic of mercury on the surface of ash originating from electrostatic precipitators of lignite and bituminous coal-fired power plants

Characteristic of mercury on the surface of ash originating from electrostatic precipitators of lignite and bituminous coal-fired power plants

Mass Flow Analysis of Mercury Transformation and Effect of Seawater Flue Gas Desulfurization on Mercury Removal in a Full-Scale Coal-Fired Power Plant

To understand the mercury speciation and mass flow in a full-scale bituminous coal-fired power plant equipped with a selective catalytic reduction (SCR) unit, an electrostatic precipitator (ESP), and a seawater flue gas desulfurization (SWFGD) scrubber, the evolution and emission of mercury was systematically measured and analyzed. The results showed that the elemental mercury (Hg0) was oxidized mainly through heterogeneous oxidation, especially in SCR, which transformed 57–64% of elemental mercury (Hg0) to oxidized mercury (Hg2+). It changed the concentrations of different mercury species and then increased the Hg2+ removal efficiencies of SWFGD, which ranged from 67 to 82%. A total of 8.24–11.54% of mercury was adsorbed by fly ash to form particulate-bound mercury (HgP) and subsequently removed by the ESP. Mass flow and mass distribution of mercury indicated that most mercury was removed and retained in the SWFGD. The heterogeneous oxidation of Hg0 in SCR and then absorption of Hg2+ by SWFGD significant...

Study on the Variance of N2O Concentration after Air Pollution Prevention Facility in Bituminous Coal-Firing Power Plant

This study intends to check the effects of air pollutant prevention facilities in bituminous coal-fired power plants on N2O gas emission concentration. Bituminous coal-fired power plants install and operate air pollution prevention facilities to prevent air pollution. The exhaust gases generated by such coal-fired power plants generally pass through a flue gas denitrification facility for removal of nitrogen oxides, a dust collector for removal of suspended matter, and a flue gas desulfurization facility for removal of sulfur oxides and are emitted through a smokestack. To check the effects of prevention facilities on N2O emission concentrations, sampling is necessary at the front end and rear end of each prevention facility. Exhaust gases were collected from the front and rear ends of the flue gas denitrification facility (SCR), the rear end of the electric dust collector (EP), and the measurement hole on the smokestack to analyze the concentrations of the gases. According to the results, it was identifi...

Distribution and Fate of Mercury in Pulverized Bituminous Coal-Fired Power Plants in Coal Energy-Dominant Huainan City, China.

A better understanding on the partitioning behavior of mercury (Hg) during coal combustion in large-scale coal-fired power plants is fundamental for drafting Hg-emission control regulations. Two large coal-fired utility boilers, equipped with electrostatic precipitators (ESPs) and a wet flue gas desulfurization (WFGD) system, respectively, in coal energy-dominant Huainan City, China, were selected to investigate the distribution and fate of Hg during coal combustion. In three sampling campaigns, we found that Hg in bottom ash was severely depleted with a relative enrichment (RE) index <7 %, whereas the RE index for fly ash (9-54%) was comparatively higher and variable. Extremely high Hg was concentrated in gypsum (≤4500 ng/g), which is produced in the WFGD system. Mass balance calculation shows that the shares of Hg in bottom ash, fly ash, WFGD products (gypsum, effluents, sludge), and stack emissions were <2, 17-32, 7-22, and 54-82%, respectively. The Hg-removal efficiencies of ESPs, WFGD, and ESPs + WFGD were 17-32, 10-29, and 36-46%, respectively. The Hg-emission factor of studied boilers was in a high range of 0.24-0.29 g Hg/t coal. We estimated that Hg emissions in all Huainan coal-fired power plants varied from 1.8 Mg in 2003 to 7.3 Mg in 2010.

Thermodynamic analysis and economic evaluation of a 1000 MW bituminous coal fired power plant incorporating low-temperature pre-drying (LTPD)

Low-temperature pre-drying (LTPD) of lignite has been identified as an effective approach to improve the efficiency of lignite fired power plants. In this study, an improved concept for the pre-drying of medium moisture bituminous coals using flue gas waste heat was proposed and its feasibility was assessed. In the proposed configuration, the boiler exhaust flue gas is drawn to dryers to heat and pre-dry the raw coal, removing a large proportion of the coal moisture and leading to an improvement in the energy efficiency of the power plant. Thermodynamic analysis and economic evaluation were performed based on a typical 1000 MW bituminous coal fired power plant incorporating the proposed LTPD concept. The results showed that the net power plant efficiency gain is as much as 0.4 percentage point with additional net power output of 9.3 MW as compared to the reference plant without coal pre-drying. This was attributed to the reduction in the moisture content from 10.3 to 2.7 wt%. The additional net economic benefit attained due to the coal pre-drying was estimated to reach $1.91 M per year. This work provides a broadly applicable and economically feasible approach to further improve the energy efficiency of power plants firing coals with medium moisture contents.

Sensitivity analysis of oxy-fuel power plant system

A comprehensive sensitivity analyses has been conducted to assess the performance of a purpose-designed 600MW supercritical steam oxy-fuel bituminous coal-fired power plant system, which includes three modes for the recirculation of flue gas (RFG), i.e. dry, half-dry and wet. The assessment was conducted by considering the changes to eight major operating parameters, the flue gas acid dew point, and the fuel consumption rate. Optimization of the system was also considered to minimize the energy loss of the oxy-fuel process. The results suggest that air leakage exerts the largest impact on the output of the system. The half-dry RFG oxy-fuel system is the most practical due to its high efficiency and easiness in operation, compared with the other two flue gas recirculation modes. The acid dew point of the half-dry RFG system is about 10°C higher than that of the dry RFG system and approximately 5°C lowers than the wet RFG system. For the optimization purpose, the improvement in the turbine system through utilizing the thermal energy of the hot flue gas is of prime importance. By heating the feed water at the outlet of the secondary feed water heater upstream of the deaerator and cooling down the hot flue gas to a temperature which is 10°C above its acid dew point, the net efficiency of an oxy-fuel process can raise by around 1.0%, which narrows the energy penalty to less than 10% compared to the reference air-firing system. This is smaller than an energy penalty of around 12% for the oxy-fuel process without the recovery of heat in the hot flue gas. It is also found that the efficiency elevation through the thermal integration with turbine system is greater for the wet model than the other two models. The oxy-fuel mode has a slightly larger net efficiency gain upon decreasing the fuel consumption rate from 600MW to 300MW.

Oxidation, reemission and mass distribution of mercury in bituminous coal-fired power plants with SCR, CS-ESP and wet FGD

Mercury (Hg) speciation variations in flue gas at the inlet and outlet of various air pollution control devices (APCDs) were studied, including a selective catalytic reactor (SCR), a cold side-electrostatic precipitator (CS-ESP), a wet flue gas desulfurization system (wet FGD) and the stack of bituminous coal-fired power plants. Effects of flue gas temperature, flow rate and selected flue gas components on Hg oxidation were also studied. The association of selected parameters on Hg0 oxidation and removal by the APCDs and the mass distribution of Hg within the system were estimated. Sampling and analysis were carried out using the Ontario Hydro Method. Solid and liquid samples were analyzed according to US EPA methods 7470A and 7471A, respectively. Hg concentration in the flue gas at the outlet boiler and stack ranged from 4.70 to 27.3μg/Sm3 and 3.1 to 0.48μg/Sm3, respectively. The overall Hg removal efficiency in the APCDs ranged from 43.8% to 94.9%, and oxidized Hg in flue gas decreased with increasing temperature. With an increase in HCl concentration, a decrease in flue gas flow rate and decreasing temperature, oxidation of elemental Hg in combustion flue gas increased. The effects of SOx and NOx concentrations on elemental Hg oxidation in flue gas were rather complex. Among the parameters studied, the most significant parameters affecting overall Hg removal in the APCDs, in order, were removal in the ESP, oxidation in the SCR system and removal in the wet FGD. Experimental data and statistical analysis confirmed the promotion of a co-beneficial control of Hg in the SCR, CS-ESP and wet FGD configurations. The mass distribution showed that 43.0% of Hg was collected in ESP fly ash, 49.4% in wet FGD by-products and effluents, 3.9% of Hg was removed in boiler bottom ash and 3.7% was released into the atmosphere. In the SCR+CS-ESP+wet FGD configuration, a major portion of Hg was distributed into the by-products and removed by the APCDs compared to the lower removal levels seen in the CS-ESP+wet FGD configuration.

Investigation of Combustion Possibility of Upgrade ECO Coal as a Blended Fuel of Bituminous Coal Fired Power Plant

Combustion possibility of upgrade ECO coal as a blended fuel of commercially thermal power plant was investigated by thermogravimetric analysis (TGA), drop tube furnace (DTF) and ignition temperature (IT) tester. TGA results showed that combustion patterns of coal samples has the simultaneous devolatilization and oxidation reactions, and the fixed carbon contained with minor content in high moisture ECO coal (HM ECO) was slowly burned to high temperature than it of dry ECO coal (Upgrade ECO) due to heat loss of moisture evaporation. The linear regression for the Arrhenius plot to the experimental data is very good, and activation energies for overall combustion of bituminous C & A (Design C & A) and Upgrade ECO are 66.83 and 29.64 kJ/mol, respectively. It was derived that activation energies of 30%, and 50% Blends produced through mixing of Upgrade ECO of 30%, and 50% to Design C & A are 31.44 and 29.98 kJ/mol in reciprocal proportion to blending ratio. Test results show that the volatile content contained in coal samples area significantly improved the combustion reactivity. The conversion behavior of the coals observed in DTF was similar to that reflected in TGA. DTF studies showed that the combustion of all blends was also completed at residence time of around 1 second, set temperature range of 1,200°C similar to commercial coal fired plant. Although the Upgrade ECO has the highest conversion than the blends, it was not appropriate as the single pulverized fuel of coal fired plant because its initial deformation (IDT) and ignition temperatures of about 1,090 and 215°C, respectively, were too low to cause the slagging in boiler, and the firing at pulverizer. The IDT of the blends ashes of Upgrade ECO of less than 30% was about 1,250°C, and, was not expected to be associated with slagging and fouling in pulverized coal fired systems. The liability of spontaneous combustion of coal samples was increased with increasing the moisture and volatile contents whereas it of Upgrade ECO was the highest due to the high volatile content and thermal diffusivity. It was therefore proposed that the combustion of blends of Upgrade ECO with less than 30% was the most appropriate for the prevention of slagging and spontaneous combustion at the pulverized coal fired boilers, and, has the excellent combustion efficiency.

Studies on Speciation Changes and Mass Distribution of Mercury in a Bituminous Coal-Fired Power Plant by Combining Field Data and Chemical Equilibrium Calculation

Transformation of mercury compounds in combustion flue gas and overall mercury mass balance in a typical bituminous coal-fired power plant were studied. Upon decreasing temperature and interaction with flue gas components, oxidized mercury increased across an electrostatic precipitator. A major fraction of particulate mercury was removed in the electrostatic precipitator, and oxidized mercury was removed in wet flue gas desulfurization. Hg was mainly speciated into elemental form in the stack emission. The measurement of mercury in a real facility and equilibrium calculation showed that coal composition, operating conditions, and flue gas components were the major factors affecting mercury emission and speciation. A reliable overall Hg mass balance was obtained from the field measurement. Mercury mainly entered from coal, and lime/limestone feeding was distributed in electrostatic precipitator fly ash (57.6−64.3%), gypsum (4.5 −12.9%), effluents (0.5−1.9%), and stack emission (15.2−27.0%). Further, the ma...

Effect of selective catalytic reactor on oxidation and enhanced removal of mercury in coal-fired power plants

The present study investigated the variation of mercury (Hg) speciation within the air pollution control devices (APCDs) in bituminous coal-fired power plants. The effect of selective catalytic reduction (SCR) system, which is mainly installed for NO x removal, on elemental Hg (Hg 0) oxidation and enhancement of Hg removal within APCDs, was studied. Hg speciations in flue gas at the inlet and outlet of each APCDs, such as SCR, cold-side electrostatic precipitator (CS-ESP) and flue gas desulphurization (FGD), were analyzed. Sampling and analysis were carried out according to Ontario Hydro Method (OHM). Overall Hg removal efficiency of APCDs, on average, was about 61% and 47% with and without SCR system, respectively. In the flue gas, Hg was mainly distributed in gaseous (elemental and oxidized) form. The oxidized to elemental Hg partitioning coefficient increased due to oxidation of Hg 0 across the SCR system and decreased due to the removal of oxidized Hg (Hg 2+) across a wet FGD system. Hg 0 oxidation across the SCR system varied from 74% to 7% in tested coal-fired power plants. The comparative study shows that the installation of an SCR system increased Hg removal efficiency and suppressed the reemission of captured Hg 0 within a wet FGD system.

Mercury emission trend influenced by stringent air pollutants regulation for coal-fired power plants in Korea

Regulatory control of mercury emission from anthropogenic sources has become a global concern in the recent past. Coal-fired power plants are one of the largest sources of anthropogenic mercury emission into the atmosphere. This paper summarizes the current reducing trend of mercury emission as co-beneficial effect by more stringent regulation changes to control primary air pollutants with introducing test results from the commercial coal-fired facilities and suggesting a guideline for future regulatory development in Korea. On average, mercury emission concentrations ranged 16.3–2.7 μg Sm −3, 2.4–1.1 μg Sm −3, 3.1–0.7 μg Sm −3 from anthracite coal-fired power plants equipped with electrostatic precipitator (ESP), bituminous coal-fired power plants with ESP + flue gas desulphurization (FGD) and bituminous coal-fired power plants with selective catalytic reactor (SCR) + cold side (CS) − ESP + wet FGD, respectively. Among the existing air pollution control devices, the best configuration for mercury removal in coal-fired power plants was SCR + CS − ESP + wet FGD, which were installed due to the stringent regulation changes to control primary air pollutants emission such as SO 2, NOx and dust. It was estimated that uncontrolled and controlled mercury emission from coal-fired power plants as 10.3 ton yr −1 and 3.2 ton yr −1 respectively. After the installation of ESP, FGD and SCR system, following the enforcement of the stringent regulation, 7.1 ton yr −1 of mercury emission has been reduced (nearly 69%) from coal-fired power plants as a co-benefit control. Based on the overall study, a sample guideline including emission limits were suggested which will be applied to develop a countermeasure for controlling mercury emission from coal-fired power plants.

CO 2 capture from power plants : Part II. A parametric study of the economical performance based on mono-ethanolamine

While the demand for reduction in CO 2 emission is increasing, the cost of the CO 2 capture processes remains a limiting factor for large-scale application. Reducing the cost of the capture system by improving the process and the solvent used must have a priority in order to apply this technology in the future. In this paper, a definition of the economic baseline for post-combustion CO 2 capture from 600 MW e bituminous coal-fired power plant is described. The baseline capture process is based on 30% (by weight) aqueous solution of monoethanolamine (MEA). A process model has been developed previously using the Aspen Plus simulation programme where the baseline CO 2-removal has been chosen to be 90%. The results from the process modelling have provided the required input data to the economic modelling. Depending on the baseline technical and economical results, an economical parameter study for a CO 2 capture process based on absorption/desorption with MEA solutions was performed. Major capture cost reductions can be realized by optimizing the lean solvent loading, the amine solvent concentration, as well as the stripper operating pressure. A minimum CO 2 avoided cost of € 33 tonne −1 CO 2 was found for a lean solvent loading of 0.3 mol CO 2/mol MEA, using a 40 wt.% MEA solution and a stripper operating pressure of 210 kPa. At these conditions 3.0 GJ/tonne CO 2 of thermal energy was used for the solvent regeneration. This translates to a € 22 MWh −1 increase in the cost of electricity, compared to € 31.4 MWh −1 for the power plant without capture.

CO 2 capture from power plants : Part I. A parametric study of the technical performance based on monoethanolamine

Capture and storage of CO 2 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 CO 2 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 CO 2 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 CO 2, which is 23% lower than the base case of 3.9 GJ/ton CO 2. 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.

Speciation and mass distribution of mercury in a bituminous coal-fired power plant

Characterization and mass balance of mercury in a coal-fired power plant were carried out in a 500 MW, bituminous coal consuming electric utility boiler. This facility is equipped with a cold-side electrostatic precipitator (ESP) and a wet flue gas desulfurization (FGD) in series as air pollution control devices (APCDs). Mercury sampling points were selected at both the up and down streams of the ESP and outlet of the FGD, which is at stack. Two different types of sampling methods were employed, one is the Ontario Hydro (OH) method (ASTM D6784) and the other is US EPA101A. Various samples were collected from the coal-fired power plant such as fuel coals, fly ash in hopper, lime/lime stone, gypsum, and effluent water from FGD. These samples were analyzed by US EPA 7470A and 7471A to understand the behavior and mass balance of mercury in the process of a coal-fired power plant. There are no significant differences between the two sampling methods, but the OH method seems to have more advantages for Hg sampling from a coal-fired power plant because mercury speciation is quite an important factor to estimate the mercury emission and control efficiency from combustion flue gas. Approximate Hg mass balance could be obtained from various samples in the study; however, a series of long-term and comprehensive study is required to evaluate the reliable Hg mass distribution and behavior in a coal-fired power plant.

Particle-Size Distributions and Heavy Metal Partitioning in Emission Gas from Different Coal-Fired Power Plants

This study investigated the emission characteristics of particulate matter (PM) and several heavy metals from different Korean coal-fired utility boilers. Emission measurements examined PM and gas emission concentrations, particle size distributions (PSDs), the partitioning of heavy metals, and the concentration of ultrafine particles. The facilities examined included two bituminous coal-fired power plants (pulverized coal combustors) and one anthracite coal-fired power plant (circulating fluidized bed combustor). Measurements were made at locations before the systems' air pollution control devices (APCDs). The PSDs prior to PM control were bimodal from all facilities. The mass ratios of the fine particle modes to larger particle modes were dependent on the ash content of the fuel and the boiler type. Additionally, the overall PM concentration before the APCDs correlates well with the ash content of the coals. Thermodynamic equilibrium predictions indicate that the metal speciation (and volatility) depends not only on the halogen content of the fuel, but also on the localized stoichiometric ratio of combustion.

Transport systems for ocean disposal of CO2 and their environmental effects

Abstract After removal from the power plant flue gas, the CO 2 has to be transported from the power plant to the deep ocean. Because of the vast quantities that need to be transported, this is a formidable engineering task. The transport systems will add significantly to the cost of CO 2 disposal, and they may pose an environmental and safety risk. Considering that a single 1000 MW bituminous coal-fired power plant equipped with CO 2 removal system will deliver between 7.2–8.2E6 T/y of CO 2 (228–260 kg/s), the only practical transport systems appear to be pipes and large tankers in which the CO 2 is transported as a liquid. The environmental impact of offshore pipes will occur mainly during the construction phase. In USA territorial waters pipes need to be buried to a depth of 61 m. This means blasting and digging through sediments and reefs. After construction, the underwater habitat will be restored in a few years. Tanker transport requires major port and docking facilities, which could lead to perturbations of coastal habitat, and contamination due to leakages, spills and effluents. As CO 2 is stored and transported as a pressurized liquid, there is a risk of rupture and release of large quantities of CO 2 . At concentrations in air above 10%, CO 2 is an asphyxiant, and at smaller concentrations it causes nausea, vomiting, diarrhea and skin lesions. However the environmental impacts and safety hazards of CO 2 transport systems can be minimized or altogether prevented with prudent management and exercise of precaution.