The Relationship of Carbon Dioxide Emissions with Coal Rank and Sulfur Content

Carbon dioxide emissions, on an equivalent energy basis, were calculated for 504 North American coals to explore the effects of coal rank and sulfur content on CO₂ emissions. The data set included coals ranging in rank from lignite through low-volatile bituminous from 15 U.S. states and Alberta, Canada. Carbon dioxide emissions were calculated from the carbon content and gross calorific value of each coal. The lowest CO₂ emissions are calculated for the high-volatile bituminous coals (198 to 211 lbs CO₂/MMBtu) and the highest for lignites and subbituminous coals (209 to 224 lbs CO₂/MMBtu). The lower CO₂ emissions from the high-volatile bituminous coals result in part from their generally higher sulfur content. However, even at equivalent sulfur contents the high-volatile bituminous coals give lower CO₂ emissions than the lower-rank coals. On average, the lowerrank coals produce 5 percent more CO₂ upon combustion than the highvolatile bituminous coals, on the basis of gross calorific value. This difference increases to 9 percent on the basis of estimated net calorific value. The net calorific value is better indicator of power plant energy production than the gross calorific value. The difference in CO₂ emissions resulting from the use of high-volatile bituminous coals and lower-rank coals is of the same order of magnitude as reductions expected from near-term combustion efficiency improvements. These results are useful to those interested in current and future CO₂ emissions resulting from coal combustion.     

Flue gas desulfurization: the state of the art

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 approximately 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 approximately 250 MWe 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 MWe and firing medium- to high-sulfur coals (i.e., coals with a sulfur content of 2% or higher) may use either LSFO or MEL.     

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.     

Estimates of 1973–1982 Annual Sulfur Oxide Emissions from Electric Utilities

Estimates of 1973–1982 annual SO₂ emissions from electric utility plants are presented in this paper. Results are based on analyses of plant level data collected by the U.S. Department of Energy on consumption and quality of fuels burned. Emissions are estimated from known information about fuel consumption, sulfur content, ash content, and control equipment. Results show that electric utility emissions decreased 16% from 1973 to 1982 and that these reductions were due to the use of lower sulfur coals and to the operation of flue gas desulfurization equipment.     

Product Gudie/1987

A computer program has been written to determine the cost of building and operating wet scrubbers on individual coal fired utilities in the states where emissions are likely to affect the acid rain problem in the eastern United States. The program differs from many other estimates since it calculates the cost for each of 831 individual sites. The capital costs for installing scrubbers on the top fifty sulfur oxide emitting plants will be about $20 billion. This will result in an increase in the cost of electricity on an average of 0.88 cents/kWh and a reduction of sulfur oxide emissions from 1980 of 7,100,000 tons per year. An additional reduction of at least 1,000,000 tons per year can be obtained by requiring all plants burning oil to burn low sulfur oil. These figures assume utilities will use least emissions dispatching and will use local coals containing at least 3.5 percent sulfur. The use of local coals should result in a further saving of at least 0.2 cents/kWh. This should make available a large supply of low sulfur coal which could reduce emissions of sulfur oxides by up to 1,000,000 tons per year. The SO₂ reductions will be continued for at least the next thirteen years and have a very significant effect through the year 2010.     

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.     

Electricity from fossil fuels without CO2 emissions: assessing the costs of carbon dioxide capture and sequestration in U.S. electricity markets.

The decoupling of fossil-fueled electricity production from atmospheric CO2 emissions via CO2 capture and sequestration (CCS) is increasingly regarded as an important means of mitigating climate change at a reasonable cost. Engineering analyses of CO2 mitigation typically compare the cost of electricity for a base generation technology to that for a similar plant with CO2 capture and then compute the carbon emissions mitigated per unit of cost. It can be hard to interpret mitigation cost estimates from this plant-level approach when a consistent base technology cannot be identified. In addition, neither engineering analyses nor general equilibrium models can capture the economics of plant dispatch. A realistic assessment of the costs of carbon sequestration as an emissions abatement strategy in the electric sector therefore requires a systems-level analysis. We discuss various frameworks for computing mitigation costs and introduce a simplified model of electric sector planning. Results from a "bottom-up" engineering-economic analysis for a representative U.S. North American Electric Reliability Council (NERC) region illustrate how the penetration of CCS technologies and the dispatch of generating units vary with the price of carbon emissions and thereby determine the relationship between mitigation cost and emissions reduction.     

Effect of multiple washing operations on the removal of potentially toxic metals from an alkaline farmland soil and the strategy for agricultural reuse

Few studies have carried out soil washing experiments using pot experiments to simulate in situ soil washing operations, particularly for alkaline soils. This study explored the effects of multiple washing operations using pot experiments on the removal efficiencies of potentially toxic metals (PTM) from alkaline farmland soil and the reuse strategy of washed soil for safe agricultural production. The results showed that the removal efficiencies of Cd, Pb, Cu, and Zn after seven washings with a mixed chelator (EDTA, GLDA, and citric acid) were 41.1%, 47.1%, 14.7%, and 26.5%, respectively, which was close to the results of the EDTA treatment. For the alkaline soil studied, the second washing with the mixed chelators most effectively removed PTM owing to the activation of them after the first washing operation. The mixed chelator more effectively increased the proportion of stable fraction of PTM and maintained soil nutrients (e.g., nitrogen content) than EDTA, indicating little disturbance of alkaline soil quality after washing with the mixed chelator. After the amendment of the washed soil, there was no visible difference in the biomass weight of crops from the soils washed with different agents, indicating that the inhibitory effect of both washing agents on plant growth was effectively alleviated. The Cd and Pb contents in Z. mays were below the threshold of Hygienical Standard for Feeds of China (GB 13078–2017) (1 and 30 mg·kg^?1). Moreover, after three cropping operations, the available concentrations of PTM in the soil washed with the mixed chelator were lower than those in the soil washed with EDTA, indicating the value and potential of agricultural reuse of alkaline farmland soil washed with the mixed chelator.

Graphical abstract

     

U and Th in some brown coals of Serbia and Montenegro and their environmental impact

GOAL, SCOPE AND BACKGROUND: The objective of this paper is to determine and compare the concentrations of U and Th in soft to hard brown (lignite to sub-bituminous) coals of Serbia and Montenegro. It also presents comparison of the obtained data on U and Th concentrations with the published data on coals located in some other countries of the world. Almost the whole coal production of Serbia and Montenegro is used as feed coals for combustion in thermal power plants. METHODS: Channel samples from open pit and underground mines and core samples were collected for hard and soft brown coals. For the analysis the samples were decomposed using microwave technique. Obtained solutions containing U and Th were analyzed by inductively coupled plasma mass spectroscopy (ICP-MS) using NIST standards. RESULTS: Concentration of U from the investigated basins and the corresponding mine fields ranges within 0.60-70.10 mg/kg, 0.65-3.20 mg/kg, 0.95-6.59 mg/kg, 1.20-6.05 mg/kg, 0.80-6.66 mg/kg, 0.18-89.90 mg/kg, 0.19-4.14 mg/kg, and 0.28-3.52 mg/kg for the Kostolac, Kolubara, Krepoljin, Sjenica, Soko Banja, Bogovina East field, Senje-Resavica and Pljevlja basins, respectively. Concentration of Th ranges within 0.20-2.60 mg/kg, 0.84-6.57 mg/kg, 1.48-6.48 mg/kg, 0.12-2.71 mg/kg, 0.13-4.95 mg/kg, 0.14-3.48 mg/kg, 0.29-3.56 mg/kg, and 0.17-1.89 mg/kg for the Kostolac, Kolubara, Krepoljin, Sjenica, Soko Banja, Bogovina East field, Senje-Resavica and Pljevlja basins, respectively. DISCUSSION: Brown coal from Senje-Resavica, Kolubara, Kostolac and Pljevlja is characterized by low U concentration. Coals form the Krepoljin, Soko Banja and Sjenica basins have slightly higher U concentrations than the mentioned group. The highest concentration of U is characteristic for the coal from the Bogovina East field. Concentration of Th in coals from Serbia and Montenegro has proved to be low. Out of all investigated coal basins, only the coal from the Krepoljin and Kolubara basins has high concentration of Th. The hydrothermally altered rocks of the Timok dacite-andesite complex, representing the basement of the Bogovina basin, could be a potential source of U, especially at the bottom part of the Lower seam of the Bogovina East field. CONCLUSIONS: This study shows that brown coals in Serbia and Montenegro (soft to hard brown coals or lignite to sub-bituminous) contain low levels of U (5.30 mg/kg, average value and 2.10 mg/kg geometric mean value) and Th (1.80 mg/kg, average value and 1.12 mg/kg geometric mean value). There are some obvious differences in concentration of U and Th in coals from different basins in Serbia and Montenegro. The approximate value for U and Th release mainly from power plants was 644.33 t and 983.46 t, respectively within the period 1965-2000 for the studied mines in Serbia, and 23.76 t and 15.05 t for the Potrlica mine (Montenegro) within the period 1965-1997. RECOMMENDATIONS: The coals in Serbia and Montenegro show no identifiable unfavourable impact on the surrounding environment, due to low natural radioactive concentration of U and Th, but further investigations concerning human health should be performed. PERSPECTIVES: Preliminary research revealed that in some Serbian coals (and, particularly, parts of the coal seam) U and Th content are rather high. Such coals should be carefully studied, as well as U and Th concentrations in ash, fly ash, waste disposals, nearby soil and ground water. Further studies should include determination of the radioactivity of all these products, and estimation of possible health impact.     

The Effective Collection of Fly Ash At Pulverized Coal-Fired Plants

The relationship between sulfur in coal, boiler exit gas temperature, and the carbon portion of fly ash have a major effect on the electrical properties of fly ash. Whether effective collection of fly ash is obtained by the electrostatic precipitator installation alone or the precipitator—mechanical combination depends primarily on a knowledge of this relationship. Fly ash electrical properties can range from a highly "resistive" to a highly "conductive" state which can appreciably alter the precipitator collection performance. A correlation of coal sulfur and boiler exit flue gas temperature is given to indicate the probability of expecting an optimum voltage—current relationship with different combinations of these factors. Carbon affects the electrical conditioning of fly ash by providing parallel paths of current leakage through the deposited dust layer. Therefore, removal of the carbon particles in a mechanical collector placed before the precipitator can alter the precipitator electrical characteristics.     

An Improved Inventory of Methane Emissions from Coal Mining in the United States

ABSTRACT

Past efforts to estimate methane emissions from underground mines, surface mines, and other coal mine operations have been hampered, to different degrees, by a lack of direct emissions data. Direct measurements have been completely unavailable for several important coal mining operations. A primary goal of this study was to collect new methane emissions measurements and other data for the most poorly characterized mining operations and use these data to develop an improved methane emission inventory for the U.S. coal mining industry. This required the development and verification of measurement methods for surface mines, coal handling operations, and abandoned underground mines and the use of these methods at about 30 mining sites across the United States. Although the study's focus was on surface mines, abandoned underground mines, and coal handling operations, evaluations were also conducted to improve our understanding of underground mine emission trends and to develop improved national data sets of coal properties. Total U.S.     

Pilot-scale study of the effect of selective catalytic reduction catalyst on mercury speciation in Illinois and Powder River Basin coal combustion flue gases

A study was conducted to investigate the effect of selective catalytic reduction (SCR) catalyst on mercury (Hg) speciation in bituminous and subbituminous coal combustion flue gases. Three different Illinois Basin bituminous coals (from high to low sulfur [S] and chlorine [Cl]) and one Powder River Basin (PRB) subbituminous coal with very low S and very low Cl were tested in a pilot-scale combustor equipped with an SCR reactor for controlling nitrogen oxides (NOx) emissions. The SCR catalyst induced high oxidation of elemental Hg (Hg0), decreasing the percentage of Hg0 at the outlet of the SCR to values <12% for the three Illinois coal tests. The PRB coal test indicated a low oxidation of Hg0 by the SCR catalyst, with the percentage of Hg0 decreasing from approximately 96% at the inlet of the reactor to approximately 80% at the outlet. The low Cl content of the PRB coal and corresponding low level of available flue gas Cl species were believed to be responsible for low SCR Hg oxidation for this coal type. The test results indicated a strong effect of coal type on the extent of Hg oxidation.     

Sequential soil washing techniques using hydrochloric acid and sodium hydroxide for remediating arsenic-contaminated soils in abandoned iron-ore mines

Sequential washing techniques using single or dual agents [sodium hydroxide (NaOH) and hydrochloric acid (HCl) solutions] were applied to arsenic-contaminated soils in an abandoned iron-ore mine area. We investigated the best remediation strategies to maximize arsenic removal efficiency for both soils and arsenic-containing washing solution through conducting a series of batch experiments. Based on the results of a sequential extraction procedure, most arsenic prevails in Fe-As precipitates or coprecipitates, and iron exists mostly in the crystalline forms of iron oxide. Soil washing by use of a single agent was not effective in remediating arsenic-contaminated soils because arsenic extractions determined by the Korean standard test (KST) methods for washed soils were not lower than 6mg kg(-1) in all experimental conditions. The results of X-ray diffraction (XRD) indicated that iron-ore fines produced mobile colloids through coagulation and flocculation in water contacting the soils, containing dissolved arsenic and fine particles of ferric arsenate-coprecipitated silicate. The first washing step using 0.2M HCl was mostly effective in increasing the cationic hydrolysis of amorphous ferrihydrite, inducing high removal of arsenic. Thus, the removal step of arsenic-containing flocs can lower arsenic extractions (KST methods) of washed soils. Among several washing trials, alternative sequential washing using 0.2M HCl followed by 1M HCl (second step) and 1M NaOH solution (third step) showed reliable and lower values of arsenic extractions (KST methods) of washed soils. This washing method can satisfy the arsenic regulation of washed soil for reuse or safe disposal application. The kinetic data of washing tests revealed that dissolved arsenic was easily readsorbed into remaining soils at a low pH. This result might have occurred due to dominant species of positively charged crystalline iron oxides characterized through the sequential extraction procedure. However, alkaline extraction using NaOH was effective in removing arsenic readsorbed onto the surface of crystalline minerals. This is because of the ligand displacement reaction of hydroxyl ions with arsenic species and high pH conditions that can prevent readsorption of arsenic.     

Sulfur dioxide and nitrogen oxides emissions from U.S. pulp and paper mills, 1980-2005

Comprehensive surveys conducted at 5-yr intervals were used to estimate sulfur dioxide (SO,) and nitrogen oxides (NO.) emissions from U.S. pulp and paper mills for 1980, 1985, 1990, 1995, 2000, and 2005. Over the 25-yr period, paper production increased by 50%, whereas total SO, emissions declined by 60% to 340,000 short tons (t) and total NO, emissions decreased approximately 15% to 230,000 t. The downward emission trends resulted from a combination of factors, including reductions in oil and coal use, steadily declining fuel sulfur content, lower pulp and paper production in recent years, increased use of flue gas desulfurization systems on boilers, growing use of combustion modifications and add-on control systems to reduce boiler and gas turbine NO, emissions, and improvements in kraft recovery furnace operations.     

Inflammatory stress response in A549 cells as a result of exposure to coal: Evidence for the role of pyrite in coal workers’ pneumoconiosis pathogenesis

On the basis of a recent epidemiological study it is hypothesized that pyrite content in coal is an important factor in coal workers’ pneumoconiosis (CWP) pathogenesis. While the role of pyrite in pathogenesis remains to be resolved, the ability of the mineral to generate reactive oxygen species (ROS) through various mechanisms is likely a contributing factor. The aim of this study was to elucidate the importance of the pyrite content of coal in generating an inflammatory stress response (ISR), which is defined as the upregulation of ROS normalized by cell viability. The ISR of A549 human lung epithelial cells in the presence of natural coal samples with variable pyrite contents was measured. Normalized to surface area, five particle loadings for each coal reference standard were analyzed systematically for a total of 24 h. The ISR generated by coals containing 0.00, 0.01, and 0.49 wt.% pyritic sulfur is comparable to,though less than, the ISR generated by inert glass beads (299% of the control). The coals containing 0.52 and 1.15 wt.% pyritic sulfur generated the greatest ISR (798% and 1426% of the control, respectively).     

A New Method to Assess Mercury Emissions: A Study of Three Coal-Fired Electric-Generating Power Station Configurations

Abstract

U.S. Environmental Protection Agency (EPA) Method 7473 for the analysis of mercury (Hg) by thermal decomposition, amalgamation, and atomic absorption spectroscopy has proved successful for use in Hg assessment at coal-fired power stations. In an analysis time of ～5 min per sample, this instrumental methodology can directly analyze total Hg—with no discrete sample preparation—in the solid matrices associated with a coal-fired power plant, including coal, fly ash, bottom ash, and flue gas desulfurization (FGD) material. This analysis technique was used to investigate Hg capture by coal combustion byproducts (CCBs) in three different coal-fired power plant configurations. Hg capture and associated emissions were estimated by partial mass balance. The station equipped with an FGD system demonstrated 68% capture on FGD material and an emissions estimate of 18% (11 kg/yr) of total Hg input. The power plant equipped with low oxides of nitrogen burners and an electrostatic precipitator (ESP) retained 43% on the fly ash and emitted 57% (51 kg/yr). The station equipped with conventional burners and an ESP retained less than 1% on the fly ash, emitting an estimated 99% (88 kg/yr) of Hg. Estimated Hg emissions demonstrate good agreement with EPA data for the power stations investigated.     

Supply curves for using powder river basin coal to reduce sulfur emissions

Supply curves were prepared for coal-fired power plants in the contiguous United States switching to Wyoming's Powder River Basin (PRB) low-sulfur coal. Up to 625 plants, representing approximately 44% of the nameplate capacity of all coal-fired plants, could switch. If all switched, more than dollars 8.8 billion additional capital would be required and the cost of electricity would increase by up to dollars 5.9 billion per year, depending on levels of plant derating. Coal switching would result in sulfur dioxide (SO2) emissions reduction of 4.5 million t/yr. Increase in cost of electricity would be in the range of 0.31-0.73 cents per kilowatt-hour. Average cost of S emissions reduction could be as high as dollars 1298 per t of SO2. Up to 367 plants, or 59% of selected plants with 32% of 44% nameplate capacity, could have marginal cost in excess of dollars 1000 per t of SO2. Up to 73 plants would appear to benefit from both a lowering of the annual cost and a lowering of SO2 emissions by switching to the PRB coal.     

Fine Paniculate Removal and S02 Absorption with a Two Stage Wet Scrubber

This paper includes results from pilot plant studies and early field demonstration units and a discussion of the application of the limestone wet scrubbing process to a low sulfur syb-butuminous coal. This latter application required the development of a hybrid two stage scrubber to enable collection of the fine particulate matter as well as removal of a significant amount of the sulfur dioxide.     

EPA SITE Demonstration of the BioTrol Soil Washing Process

A pilot-scale soil washing process, patented by BioTrol, Inc., was demonstrated on soil contaminated by wood treating waste, primarily pentachlorophenol (PCP) and creosote-derived polynuclear aromatic hydrocarbons (PAHs). Although soil washing was the main object of this demonstration, the treatment train that was evaluated included two other BioTrol technologies for treatment of waste streams from the soil washer. The three technologies were: ? The BioTrol Soil Washer (BSW)—a volume reduction process, which uses water to separate contaminated soil fractions from the bulk of the soil.

? The BioTrol Aqueous Treatment System (BATS)—a biological water treatment process.

? The Slurry Bioreactor (SBR)—a BioTrol biological slurry treatment process conducted in an EIMCO BIOLIFT^tm reactor.

The sandy soil at the site, consisting of less than 10 percent of fines, was well suited for treatment by soil washing. The soil washer was evaluated in two tests on soil samples containing 130 ppm and 680 ppm of PCP, respectively.

The BSW successfully separated the feed soil (dry weight basis) into 83 percent of washed soil, 10 percent of woody residues, and 7 percent of fines. The washed soil retained about 10 percent of the feed soil contamination while 90 percent of the feed soil contamination was contained within the woody residues, fines, and process water.

The soil washer achieved up to 89 percent removal of PCP and 88 percent of total PAHs, based on the difference between their levels in the as-is (wet) feed soil and the washed soil. PCP concentrations of 14 ppm and 87ppm in the washed soil were achieved from PCP concentrations of 130 ppm and 680ppm in the feed soil. Concentrations of total PAHs were reduced from 247 ppm to 42 ppm and 404 ppm to 48 ppm, respectively, in the two tests.

The BATS degraded up to 94 percent of PCP in the process water from soil washing. PAH removal could not be determined due to low influent concentrations.

The SBR achieved over 90 percent removals of PCP and 70 to 90 percent removals of PAHs from the slurry of contaminated fines from soil washing. However, steady state operation was not achieved during the single test and the results were variable.

Cost of a commercial-scale soil washing, assuming use of all three technologies, was estimated to be $168 per ton of soil treated. Incineration of woody material accounts for 76 percent of the cost.