Development of Federal Air Standards to Reduce Sulfur Dioxide Emissions from New Industrial Boilers

Federal new source performance standards to control air emissions of sulfur dioxide from new industrial boilers were proposed by EPA on June 19, 1986. These standards would require boiler owners to reduce SO₂ emissions by 90 percent and meet an emission limit of 1.2 lb/MM Btu of heat input for coal-fired boilers and 0.8 lb/MM Btu for oil-fired boilers. In developing these standards, several regulatory options were considered, from standards that could be met by firing low sulfur fuels to standards that would necessitate flue gas treatment. The environmental, economic, and cost impacts of each option were analyzed. National impacts were estimated by a computer model that projects the population of new boilers over the 5-year period following proposal, predicts the compliance strategy that will be used to comply with the particular option (always assuming that the lowest cost method of compliance will be selected), and estimates the resulting emission reductions and costs. Impacts on specific industries and on model boilers were also analyzed. This paper focuses on these analyses and their results. The Agency's conclusions from these analyses, which led to the decision to establish percent reduction standards, are provided, and the proposed SO₂ standards are summarized. The proposed standards also include an emission limit for particulate matter from oil-fired boilers (0.1 lb/MM Btu). However, this article focuses only on the SO₂ standards.     

Nitrogen Oxides Emission Control Options for Coal-Fired Electric Utility Boilers

Abstract

Recent regulations have required reductions in emissions of nitrogen oxides (NO_x) from electric utility boilers. To comply with these regulatory requirements, it is increasingly important to implement state-of-the-art NO_x control technologies on coal-fired utility boilers. This paper reviews NO_x control options for these boilers. It discusses the established commercial primary and secondary control technologies and examines what is being done to use them more effectively. Furthermore, the paper discusses recent developments in NO_x controls. The popular primary control technologies in use in the United States are low-NO_x burners and overfire air. Data reflect that average NO_x reductions for specific primary controls have ranged from 35% to 63% from 1995 emissions levels. The secondary NO_x control technologies applied on U.S. coal-fired utility boilers include reburning, selective noncatalytic reduction (SNCR), and selective catalytic reduction (SCR). Thirty-six U.S. coal-fired utility boilers have installed SNCR, and reported NO_x reductions achieved at these applications ranged from 15% to 66%. Recently, SCR has been installed at >150 U.S. coal-fired utility boilers. Data on the performance of 20 SCR systems operating in the United States with low-NO_x emissions reflect that in 2003, these units achieved NO_x emission rates between 0.04 and 0.07 lb/10⁶ Btu.     

Relationship of Particulate Control,SO2 Removal,and Waste Management

Results with the EPRI 2.5 MW(e) Integrated Environmental Control Pilot Plant (IECPP) indicate the interrelationship of particulate penetration, SO₂ scrubber operation, waste production, and waste properties. Tests compared a fabric filter/wet scrubber and ESP/wet scrubber, the latter operated to simulate 1979 New Source Performance Standards (NSPS), 1971 NSPS, and pre-NSPS ESP units. Tests were conducted with low-sulfur coal producing a flue gas concentration of400ppm; flue gas spiking could be used to increase SO₂ to 2000 ppm. Scrubber waste was dewatered in a thickener and vacuum belt filter (to 55 percent solids content), and mixed with fly ash. The pilot SO₂ scrubber—when preceded by an ESP and forced to operate in zero-discharge—captured less SO₂ than when preceded by a fabric filter. Also, scrubber operation with the ESP produced a greater quantity of waste with difficult handling characteristics, as compared to operation with the fabric filter. These difficulties occurred with particulate penetration above 0.10 lb/MBtu, which could reduce reagent utilization to 80percent. These results are attributable to inhibited limestone dissolution due to accumulation of an aluminum/fluoride compound. For both lowsulfur and simulated high-sulfur test conditions, allowing wastewater discharge to purge aluminum/fluoride content restored performance to design levels. Particulate control efficiency also affected solid waste physical properties. The fabric filter/wet scrubber produced the lowest solid waste permeability (10^?8 cm/s). ESP operation at 1979 NSPS and pre-1971 NSPS ESPs increased solid waste permeability to 10^?7 and 10^?6 cm/s, respectively. These results are meaningful for SO₂ scrubbers both for new plants and for retrofit to units with pre-NSPS ESPs, and could become significant with the increasing trend to restricted water discharge.     

Comparison of Air Pollutant Emissions from Vaporizing and Air Atomizing Waste Oil Heaters

Information presented in this paper is directed to individuals concerned with emissions from combustion of waste crankcase oil for space heating. Studies were performed to characterize gaseous and particulate emissions and vaporizing pot solid residues resulting from the combustion of waste crankcase oil. Two types of waste oil burners were tested. One was a vaporizing oil burner rated at 35.2 kW (120,000 Btu/h heat input), and the other was an air atomizing oil burner rated at 73.3 kW (250,000 Btu/h heat input). Except for NO_X and SO_X, gaseous emissions were similar to those from conventional distillate oil combustion. NO_X and SO_X emissions were higher due to higher fuel nitrogen and sulfur concentrations. Waste oil from automotive use showed higher inorganic levels than crankcase oil used for truck engine lubrication. Both burner types discharged high levels of metallic species, but the air atomizing unit had much higher stack emission levels than did the vaporizing pot system. Also, particulate loading levels were an order of magnitude higher for the air atomizing burner than for the vaporizing pot burner when firing the waste oils. However, the vaporizing pot burner generated a waste residue containing the majority of its elemental emissions. Elements which exceeded threshold limit values for one or both heaters were cadmium, chromium, cobalt, copper, iron, lead, nickel, phosphorus, and zinc. However, the nickel and much of chromium appeared to be a sampling artifact caused by the stainless steel sampling system.     

Emissions of Sulfur Trioxide from Coal-Fired Power Plants

Abstract

Emissions of sulfur trioxide (SO₃) are a key component of plume opacity and acid deposition. Consequently, these emissions need to be low enough to not cause opacity violations and acid deposition. Generally, a small fraction of sulfur (S) in coal is converted to SO₃ in coal-fired combustion devices such as electric utility boilers. The emissions of SO₃ from such a boiler depend on coal S content, combustion conditions, flue gas characteristics, and air pollution devices being used. It is well known that the catalyst used in the selective catalytic reduction (SCR) technology for nitrogen oxides control oxidizes a small fraction of sulfur dioxide in the flue gas to SO₃. The extent of this oxidation depends on the catalyst formulation and SCR operating conditions. Gas-phase SO₃ and sulfuric acid, on being quenched in plant equipment (e.g., air preheater and wet scrubber), result in fine acidic mist, which can cause increased plume opacity and undesirable emissions. Recently, such effects have been observed at plants firing high-S coal and equipped with SCR systems and wet scrubbers. This paper investigates the factors that affect acidic mist production in coal-fired electric utility boilers and discusses approaches for mitigating emission of this mist.     

Problems of Meeting Multiple Air Quality Objectives for Coal-Fired Utility Boilers

Gaseous wastes and particulate emissions are produced in the process of burning coal to produce electrical energy. In attempting to control these gaseous wastes, changes in the operation efficiency of boilers and secondary equipment are likely to result, and in addition liquid and solid waste streams are produced. The interrelationships among the various forms of wastes and the effects of air quality control on process efficiency are often overlooked in studies of environmental quality management.

The study was undertaken to evaluate the technical alternatives for handling gaseous and particulate emissions from coal-fired boilers and to determine the feasibility of meeting several standards simultaneously. The gaseous emissions of major importance in the combustion of coal are parti culates, oxides of sulfur, and oxides of nitrogen. Particulates can be controlled by a tradeoff among further preparation at the mine (for additional ash removal), type of boiler, use of dust control equipment and high stacks for dispersion of residual emissions, if ambient air standards are considered. Oxides of sulfur reduction depends currently on fuel substitution, limestone additives in the boiler and some form of contact process such as wet scrubbing, or the use of high stacks. Oxides of nitrogen control in coal fired boilers is restricted to small reductions by either changes in boiler operation, such as lower excess air levels, adsorption during wet scrubbing or by dispersion from high stacks.     

Emission Characteristics of Granulated Fuel Produced from Sewage Sludge and Coal Slime

Abstract

The neutralization of wastewater treatment residues is an issue for many countries. The European Union (EU) legal regulations have limited the use of the residues in agriculture and implemented a ban for their disposal. Therefore, urgent action should be taken to find solutions for the safe disposal of sewage sludge. The problem refers in particular to the new EU member countries, including Poland, where one can now observe an intensive development of sewage system networks and new sewage treatment plants. At the same time, these countries have few installations for thermal sewage sludge utilization (e.g., there is only one installation of that type in Poland). Simultaneously, there are many coal-fired mechanical stoker-fired boilers in some of these countries. This paper presents suggestions for the production of granulated fuel from sewage sludge and coal slime. Additionally, among others, lime was added to the fuel to decrease the sulfur compounds emission. Results are presented of research on fuel with two average grain diameters (～15 and 35 mm). The fuel with such diameters is adapted to the requirements of the combustion process taking place in a stokerfired boiler. The research was aimed at identifying the behavior of the burning fuel, with special attention paid to its emission properties (e.g., to the emissions of oxides of nitrogen [NO_x], sulfur dioxide [SO₂], and carbon mon-oxide [CO], among others). The concentration and emission values were compared with similar results obtained while burning hard coal. The combustion process was carried out in a laboratory stand where realization of the large-scale tests is possible. The laboratory stand used made simulation possible for a wide range of burning processes in mechanical stoker-fired boilers.     

The MACT for petroleum refinery FCCs is a fraud!

This paper is a continuation of the author's research on the MACT regulation for abating pollution from Petroleum Refinery FCCs in the US. This paper highlights the flaws in the recently promulgated MACT for NSPS and non-NSPS FCC units. It details the inadequacies and the potential for perversity in the New Source Performance Standards (NSPS) that are an integral part of the FCC MACT. It elaborates upon the potential for multi-media risk-exacerbations under the NSPS resulting from changes in feedstock quality, 'unit conversion', advances in cracking technology (that favour inferior crudes and feedstock), lack of NSPS standards for NO_x emissions, inter-unit transfer of contaminants/pollutants within a refinery, and the blind eye turned by RCRA to the disposal of spent FCC catalyst waste to landfills. The paper also questions EPA's motives as regards sub-categorisation of FCCs and SBREFA concessions. This paper proposes four standards that remedy these deficiencies. The first standard controls heavy metals, PM, and SO_x (along with SO₂), while the second proposes an integrated percentile control standard for CO (VOC) and NO_x emissions. The paper also proposes a percentile standard for opacity and a spent catalyst tax to control environmental risk posed by disposal of spent FCC catalyst waste to landfills. It explains the calibration of the proposed standards using a novel strategy to bridge the regulatory gap between NSPS, MACT and Residual Risk standards and demonstrates how the calibrated standards apply to FCCs processing feedstock of different qualities. The paper concludes by urging the US EPA to rescind the NSPS and the MACT for FCCs and re-promulgate an integrated set of standards for criteria and toxic pollutants along the lines proposed in this paper.     

PM2.5 chemical source profiles for vehicle exhaust, vegetative burning, geological material, and coal burning in Northwestern Colorado during 1995

PM_2.5 (particles with aerodynamic diameters less than 2.5 μm) chemical source profiles applicable to speciated emissions inventories and receptor model source apportionment are reported for geological material, motor vehicle exhaust, residential coal (RCC) and wood combustion (RWC), forest fires, geothermal hot springs; and coal-fired power generation units from northwestern Colorado during 1995. Fuels and combustion conditions are similar to those of other communities of the inland western US. Coal-fired power station profiles differed substantially between different units using similar coals, with the major difference being lack of selenium in emissions from the only unit that was equipped with a dry limestone sulfur dioxide (SO₂) scrubber. SO₂ abundances relative to fine particle mass emissions in power plant emissions were seven to nine times higher than hydrogen sulfide (H₂S) abundances from geothermal springs, and one to two orders of magnitude higher than SO₂ abundances in RCC emissions, implying that the SO₂ abundance is an important marker for primary particle contributions of non-aged coal-fired power station contributions. The sum of organic and elemental carbon ranged from 1% to 10% of fine particle mass in coal-fired power plant emissions, from 5% to 10% in geological material, >50% in forest fire emissions, >60% in RWC emissions, and >95% in RCC and vehicle exhaust emissions. Water-soluble potassium (K⁺) was most abundant in vegetative burning profiles. K⁺/K ratios ranged from 0.1 in geological material profiles to 0.9 in vegetative burning emissions, confirming previous observations that soluble potassium is a good marker for vegetative burning.     

Panel Calls Beneficiation-FGD Combination “Most Economical,Best Ail-Around Choice”

The Commerce Technical Advisory Board (CTAB) Panel on Sulfur Oxide mission Control Technology was established in the spring of_1975 by the Secretary of Commerce in response to the urgent need for the use of coal to meet the Nation’s energy requirements, while maintaining the SO₂ emission standards resulting from the Clean Air Act of 1970.

The Panel’s 20 members and 11 consultants, drawn broadly from industry, government, and academia are highly qualified in the diverse fields pertinent to SO_x control technologies. They committed themselves to make an objective analysis of how soon, at what cost, and with what trade-offs commercially available SO₂ continuous emissions controls can be installed, with arrangements for waste disposal, in all coal-fifed electricity generating plants in the populous Northeastern quadrant of the United States.

In its final report, submitted on September 10, 1975 to Dr. Betsy Ancker-Johnson, Assistant Secretary for Science and Technology, U. S.Department of Commerce, and Chairman of the Commerce Technical Advisory Board, the Panel concludes that installation and operation of continuous SO_x emission controls on all Northeastern coal-fired electricity generating plants cannot be met until the early 1980’s, and then only with a maximum effort beginning immediately. Specific site and market constraints will determine the most economical and practical control technology for any given plant. The Panel believes that coal beneficiation, alone where it meets standards, or combined with lime/limestone flue gas desulfurization, often represents the lowest cost control technique.     

Nitrogen oxides emission control options for coal-fired electric utility boilers

Recent regulations have required reductions in emissions of nitrogen oxides (NOx) from electric utility boilers. To comply with these regulatory requirements, it is increasingly important to implement state-of-the-art NOx control technologies on coal-fired utility boilers. This paper reviews NOx control options for these boilers. It discusses the established commercial primary and secondary control technologies and examines what is being done to use them more effectively. Furthermore, the paper discusses recent developments in NOx controls. The popular primary control technologies in use in the United States are low-NOx burners and overfire air. Data reflect that average NOx reductions for specific primary controls have ranged from 35% to 63% from 1995 emissions levels. The secondary NOx control technologies applied on U.S. coal-fired utility boilers include reburning, selective noncatalytic reduction (SNCR), and selective catalytic reduction (SCR). Thirty-six U.S. coal-fired utility boilers have installed SNCR, and reported NOx reductions achieved at these applications ranged from 15% to 66%. Recently, SCR has been installed at >150 U.S. coal-fired utility boilers. Data on the performance of 20 SCR systems operating in the United States with low-NOx emissions reflect that in 2003, these units achieved NOx emission rates between 0.04 and 0.07 lb/10(6) Btu.     

ESP Performance with Atmospheric Fluidized-Bed Combustion

Electric utilities considering atmospheric fluidized-bed combustion (AFBC) as an economic way to reduce SO₂ and NO_x emissions at coal-fired power plants must evaluate the impact AFBC will have on existing or planned plant systems and components. Because fly ash in AFBC units can have characteristics significantly different from that generated in pulverized-coal-fired boilers, a particular concern in this regard is the performance of the plant's particulate control equipment.     

Simplified Models of U.S. Acid Rain Control Costs

Simplified algorithms are presented for estimating the cost of controlling sulfur dioxide (SO₂) emissions from existing coal-fired power plants on a state-by-state basis. Results are obtained using the detailed Utility Control Strategy Model (UCSM) to calculate the Impacts of emission reductions ranging from approximately 30 percent to 90 percent of projected 1995 emissions for 18 different scenarios and 36 states. Scenarios include the use of two dry SO₂ removal technologies (lime spray dryers and LIMB) as potential options for power plant retrofit, in addition to currently available emission control options including coal switching, coal cleaning and wet flue gas desulfurization (FGD). Technical assumptions relating to FGD system performance and the upgrading of existing cold-side electrostatic precipitators (ESP) for reduced sulfur levels are also analyzed, along with the effects of interest rates, coal prices, coal choice restrictions, plant lifetime, and plant operating levels. Results are summarized in the form of a 3-term polynomial equation for each state, giving total annualized SO₂ control cost as a function of the total SO₂ emissions reduction for each scenario. Excellent statistical fits to UCSM results are obtained for these generalized equations.     

Simultaneous Control of Hg0, SO2, and NOx by Novel Oxidized Calcium-Based Sorbents

Abstract

Efforts to develop multipollutant control strategies have demonstrated that adding certain oxidants to different classes of Ca-based sorbents leads to a significant improvement in elemental Hg vapor (Hg⁰), SO₂, and NO_x removal from simulated flue gases. In the study presented here, two classes of Ca-based sorbents (hydrated limes and silicate compounds) were investigated. A number of oxidizing additives at different concentrations were used in the Ca-based sorbent production process. The Hg⁰, SO₂, and NO_x capture capacities of these oxidant-enriched sorbents were evaluated and compared to those of a commercially available activated carbon in bench-scale, fixed-bed, and fluid-bed systems. Calcium-based sorbents prepared with two oxidants, designated C and M, exhibited Hg⁰ sorp-tion capacities (~100 μg/g) comparable to that of the activated carbon; they showed far superior SO₂ and NO_x sorption capacities. Preliminary cost estimates for the process utilizing these novel sorbents indicate potential for substantial lowering of control costs, as compared with other processes currently used or considered for control of Hg⁰, SO₂, and NO_x emissions from coal-fired boilers. The implications of these findings toward development of multipollutant control technologies and planned pilot and field evaluations of more promising multipollutant sorbents are summarily discussed.     

Retrofit NO x Control Options

Modifications to the combustion process have been the basis for NO_x control on new coal-fired power plants to meet federal New Source Performance Standards (NSPS) Promulgated in 1971 and revised in 1978. In the event that retrofit NO_x control is required on pre-NSPS plants, low-NO_x combustion will likely be the least cost approach, if such controls can be successfully applied to the wide diversity of these older utility boiler designs now in operation. A series of retrofit low-NOx combustion demonstrations supported by EPRI and electric utility companies are intended to establish the technical and economic feasibility of this approach.     

The Regulation of Toxic Air Pollutants A Critical Review

ABSTRACT

Passage of the 1990 Clean Air Act Amendments launched the Acid Rain Program in the United States. This initiative, based on the market mechanism of a sulfur dioxide tradable “allowance” system, was a dramatic departure from traditional command and control strategies designed to reduce air pollution emissions. Power plant managers have flexibility under the program to select and implement a variety of options to reduce emissions below mandated levels. Federal agencies have collected annual performance data for affected facilities covered by the program for a number of years. Coal-burning plants are typically greater generators of sulfur dioxide (SO₂) than oil burners of equivalent size. This study examined the effect of fuel type as a significant factor influencing a plant's achievement in reducing pollution emissions. Achievement was measured by using a derived variable, delta (A), defined as the difference between pounds of SO₂ produced divided by the energy (in million Btu) generated, for the years 1990 and 1995. Rigorous nonparametric statistical analyses were used to compare the two populations of coal-fired and oil-fired plants. Results indicated that coal-burning facilities achieved greater program success, measured by the expected value of delta, than the oil combustors for the five-year period reviewed. Since utility managers must take steps to ensure all applicable requirements of the program are met, findings of the inquiry should prove to be useful in assessing achievable emissions reductions and aid in long-range facility planning.     

A Life-Cycle Inventory Model of Municipal Solid Waste Combustion

ABSTRACT

Evaluation of alternate strategies for municipal solid waste (MSW) management requires models to calculate environmental emissions as a function of both waste quantity and composition. A methodology to calculate waste component-specific emissions associated with MSW combustion is presented here. The methodology considers emissions at a combustion facility as well as those avoided at an electrical energy facility because of energy recovered from waste combustion. Emission factors, in units of kg pollutant per metric ton MSW entering the combustion facility, are calculated for CO₂-biomass, CO₂-fossil, SO_x , HCl, NO_x , dioxins/furans, PM, CO, and 11 metals. Water emissions associated with electrical energy offsets are also considered. Reductions in environmental emissions for a 500-metric-ton-per-day combustion facility that recovers energy are calculated.     

Investigation of Selective Catalytic Reduction Impact on Mercury Speciation under Simulated NOx Emission Control Conditions

Abstract

Selective catalytic reduction (SCR) technology increasingly is being applied for controlling emissions of nitrogen oxides (NO_x) from coal-fired boilers. Some recent field and pilot studies suggest that the operation of SCR could affect the chemical form of mercury (Hg) in coal combustion flue gases. The speciation of Hg is an important factor influencing the control and environmental fate of Hg emissions from coal combustion. The vanadium and titanium oxides, used commonly in the vanadia-titania SCR catalyst for catalytic NO_x reduction, promote the formation of oxidized mercury (Hg²⁺).

The work reported in this paper focuses on the impact of SCR on elemental mercury (Hg⁰) oxidation. Bench-scale experiments were conducted to investigate Hg⁰ oxidation in the presence of simulated coal combustion flue gases and under SCR reaction conditions. Flue gas mixtures with different concentrations of hydrogen chloride (HCl) and sulfur dioxide (SO₂) for simulating the combustion of bituminous coals and subbituminous coals were tested in these experiments. The effects of HCl and SO₂ in the flue gases on Hg⁰ oxidation under SCR reaction conditions were studied. It was observed that HCl is the most critical flue gas component that causes conversion of Hg⁰ to Hg²⁺ under SCR reaction conditions. The importance of HCl for Hg⁰ oxidation found in the present study provides the scientific basis for the apparent coal-type dependence observed for Hg⁰ oxidation occurring across the SCR reactors in the field.     

Flue Gas Desulfurization: The State of the Art

ABSTRACT

Coal-fired electricity-generating plants may use SO₂ scrubbers to meet the requirements of Phase II of the Acid Rain SO₂ Reduction Program. Additionally, the use of scrubbers can result in reduction of Hg and other emissions from combustion sources. It is timely, therefore, to examine the current status of SO₂ scrubbing technologies. This paper presents a comprehensive review of the state of the art in flue gas desulfurization (FGD) technologies for coal-fired boilers.

Data on worldwide FGD applications reveal that wet FGD technologies, and specifically wet limestone FGD, have been predominantly selected over other FGD technologies. However, lime spray drying (LSD) is being used at the majority of the plants employing dry FGD technologies. Additional review of the U.S. FGD technology applications that began operation in 1991 through 1995 reveals that FGD processes of choice recently in the United States have been wet limestone FGD, magnesium-enhanced lime (MEL), and LSD. Further, of the wet limestone processes, limestone forced oxidation (LSFO) has been used most often in recent applications.

The SO₂ removal performance of scrubbers has been reviewed. Data reflect that most wet limestone and LSD installations appear to be capable of ~90% SO₂ removal. Advanced, state-of-the-art wet scrubbers can provide SO₂ removal in excess of 95%.

Costs associated with state-of-the-art applications of LSFO, MEL, and LSD technologies have been analyzed with appropriate cost models. Analyses indicate that the capital cost of an LSD system is lower than those of same capacity LSFO and MEL systems, reflective of the relatively less complex hardware used in LSD. Analyses also reflect that, based on total annualized cost and SO₂ removal requirements: (1) plants up to ~250 MW_e in size and firing low- to medium-sulfur coals (i.e., coals with a sulfur content of 2% or lower) may use LSD; and (2) plants larger than 250 MW_e and firing medium- to high-sulfur coals (i.e., coals with a sulfur content of 2% or higher) may use either LSFO or MEL.     

The comparison of fossil carbon fraction and greenhouse gas emissions through an analysis of exhaust gases from urban solid waste incineration facilities

In this study, in order to understand accurate calculation of greenhouse gas emissions of urban solid waste incineration facilities, which are major waste incineration facilities, and problems likely to occur at this time, emissions were calculated by classifying calculation methods into 3 types. For the comparison of calculation methods, the waste characteristics ratio, dry substance content by waste characteristics, carbon content in dry substance, and ¹²C content were analyzed; and in particular, CO₂ concentration in incineration gases and ¹²C content were analyzed together. In this study, 3 types of calculation methods were made through the assay value, and by using each calculation method, emissions of urban solid waste incineration facilities were calculated then compared. As a result of comparison, with Calculation Method A, which used the default value as presented in the IPCC guidelines, greenhouse gas emissions were calculated for the urban solid waste incineration facilities A and B at 244.43 ton CO₂/day and 322.09 ton CO₂/day, respectively. Hence, it showed a lot of difference from Calculation Methods B and C, which used the assay value of this study. It is determined that this was because the default value as presented in IPCC, as the world average value, could not reflect the characteristics of urban solid waste incineration facilities. Calculation Method B indicated 163.31 ton CO₂/day and 230.34 ton CO₂/day respectively for the urban solid waste incineration facilities A and B; also, Calculation Method C indicated 151.79 ton CO₂/day and 218.99 ton CO₂/day, respectively.

Implications: This study intends to compare greenhouse gas emissions calculated using ¹²C content default value provided by the IPCC (Intergovernmental Panel on Climate Change) with greenhouse gas emissions calculated using ¹²C content and waste assay value that can reflect the characteristics of the target urban solid waste incineration facilities. Also, the concentration and ¹²C content were calculated by directly collecting incineration gases of the target urban solid waste incineration facilities, and greenhouse gas emissions of the target urban solid waste incineration facilities through this survey were compared with greenhouse gas emissions, which used the previously calculated assay value of solid waste.