Fanny Creek drains from Island Block opencast coal mine, near Reefton on the West Coast of the South Island of New Zealand, and is impacted by acid mine drainage (AMD). The objectives of this study were to characterise drainage chemistry in Fanny Creek catchment, and to determine optimal passive treatment strategies for Fanny Creek AMD for future pilot or full-scale application. This was undertaken by monthly monitoring in Fanny Creek catchment between February 2008 and January 2009 to collect drainage chemistry and flow data. Laboratory trials of suitable passive AMD treatment systems were conducted and their treatment performance assessed to select and design optimal passive treatment strategies for Fanny Creek AMD. Oxidation of pyrite in Brunner Coal Measure sediments at Island Block mine generates AMD. Fanny Creek originates from a number of AMD seeps on the eastern waste rock slope of Island Block mine. Seeps have low pH (<3.23) and a single detailed metal analysis indicates drainage is enriched with aluminium and iron, and contains elevated concentrations of manganese, copper, nickel, zinc and cadmium relative to applicable water quality criteria such as ANZECC guidelines. Acidity and metal loadings of drainage in the catchment indicates AMD from the northern waste rock slope contributes most of the acidity (~70%) and metal (60%) in Fanny Creek, and acts to re-dissolve additional metals upon mixing with drainage from other slopes. The most suitable location for a passive AMD treatment system in Fanny Creek catchment is on the Waitahu Valley floor, near monitoring site R12, because this allows for sediment removal prior to a treatment system. Fanny Creek AMD at site R12 was characterized in detail because this data assists with selection and design of passive AMD treatment systems. Fanny Creek at site R12 contains on average 6.0 mg/L aluminium, 1.3 mg/L iron, 3.1 mg/L manganese, 0.49 mg/L zinc, 0.14 mg/L nickel, 0.0071 mg/L copper and 0.00048 mg/L cadmium. Average pH at site R12 was 3.95, calculated acidity averaged 42.7 mg CaCO₃/L, and flow rate ranged from 1.5 L/s to about 30 L/s. Acidity and metal generation from Island Block mine increases linearly with flow in the catchment, and therefore Fanny Creek drainage chemistry is not significantly affected by rainfall dilution. Natural attenuation of AMD occurs by addition of un-impacted alkaline drainage from Greenland Group basement rocks, wetland ecosystem processes, and geochemical reactions along Fanny Creek that decrease acidity and metal concentrations before AMD discharges into the Waitahu River. During low flow conditions (summer months), surface flow of AMD into the Waitahu River does not occur because of subsurface flow loss. Three suitable passive AMD treatment options for Fanny Creek AMD were selected and trialed at ‘bench top’ scale in a laboratory. These included a sulfate reducing bioreactor (SRBR), a limestone leaching bed (LLB), and an open limestone channel (OLC). The potential to mix Waitahu River water with Fanny Creek to neutralize AMD was also investigated. Fanny Creek AMD was employed for laboratory trials, and influent flow rates into SRBR, LLB and OLC systems were regulated to assess performance at different hydraulic retention times (HRT). Optimal HRTs for future treatment system designs were determined from effective AMD treatment thresholds, and include 51 hours, 5 hours and 15 hours for SRBR, LLB and OLC systems, respectively. To determine optimal treatment options for Fanny Creek AMD the effectiveness of each trial option was compared to applicable water quality criteria, and scale up implications of treatment options was assessed. The SRBR system had most effective AMD treatment, with water quality criteria achieved for metals, greatest alkalinity generation, and highest pH increase. However, a full scale SRBR system has significant size requirements, and long term treatment performance may be limited. The LLB system decreased metals to below, or just slightly above criteria for all metals, and has significantly smaller size requirements compared to a SRBR system. The OLC system was least effective, with effluent above water quality criteria for all metals except iron, and with lowest alkalinity generation. The Waitahu River is capable of neutralizing AMD because it is slightly alkaline. The flow volume of river water required for neutralization is between 65 L/s and 140L/s, which can be gravity fed to mix with Fanny Creek. These results indicate that either a LLB treatment system or the Waitahu River Mixing option are the optimal passive treatment strategies for Fanny Creek AMD. On site pilot scale testing of SRBR and LLB systems, and the Waitahu River Mixing option is recommended because of AMD treatment uncertainty, and to more accurately select and design full scale passive treatment strategies.

In recent decades, advances in low NOₓ coal combustion and increasingly strict CO₂ reduction mandates have changed power plant boiler operations quite significantly. As a result of these necessary efforts, the characteristics of fly ash generated at many power plants have also changed. In particular, increases in unburned carbon content have been observed with detrimental implications on the utility of these fly ashes in concrete applications. Over the same time period, the combustion of biomass for energy generation has received increased attention due to the potential benefits of reducing CO₂ emissions and improved sustainability when compared to fossil fuel combustion. Biomass is directly burned, gasified, or co-fired with coal to achieve this goal. Currently, close to 120 million metric tons of coal combustion by products are produced in the U.S. annually. As with coal combustion, production of energy from biomass combustion/gasification results in significant by-product generation that must either be productively reused or geologically disposed. While much research effort has been devoted to understanding the properties and potential productive reuse alternatives for coal combustion residuals, relatively little work has been done on the by-products of biomass combustion. This study investigated the properties and engineering behavior of sixteen ash samples that were produced in eleven different power plants. Specifically, three high carbon content Class F fly ashes, eight coal and biomass co-fired ashes, three pure biomass ash samples, and two high quality, low carbon content ash samples, one of which is commercially marketed (for reference) were chosen. The various ash samples were characterized by means of: electron microscopy; laser diffraction and dry sieve particle size analysis; loss on ignition and total organic carbon analysis; specific surface area analysis; as well as x-ray fluorescence and x-ray diffraction. The ash samples were also investigated for their potential engineering application in the fired clay brick industry, as low-cost adsorptive agents, and in alkali activated geopolymer synthesis for geotechnical and geoenvironmental applications. Results from physical and chemical characterization of the ash samples show no significant differences between pure coal ash and coal co-fired with biomass ash samples from the same power plant. However, there are significant morphological, chemical, and mineralogical differences between coal ash and pure biomass ash. Unlike pure coal ash, biomass ash is not composed primarily of aluminosilicate glass cenospheres but rather consists mainly of charred, fibrous woody remnants with elevated calcite content as compared to coal ash. Bench scale fired bricks produced by partial replacement of clay material with high carbon coal ash, co-fired ash, and pure biomass ash, respectively, was successful. Physical properties of a number of the mix designs exceeded the highest ASTM weathering grade requirements. As sorptive agents, high carbon concentrates from coal and co-fired ash samples, along with all the biomass ash samples, showed significant uptake of lead. The unaltered as- received ash samples (i.e. no acid or steam activation) showed only moderate arsenic (V) and selenium (VI) sorption capacity. Finally, solidification/stabilization by geopolymerization of high carbon content, co-fired ash with as little as 3 molar NaOH in the activator solution was successful, possibly paving the way for various geotechnical and geoenvironmental applications in ground improvement and soil/ash-pond stabilization.

Nigeria is presently being faced with a growing electricity demand problem following its population growth rate. The total installed capacity is far less than the current demand for electricity supply. As a way of bridging out this supply gap, the federal government is mobilizing all of its potential energy options. Coal is widely used for power generation in many countries. But today, the continued usage of coal for power generation is being challenged by the disturbing global warming phenomenon. This is due to the quantity of uncontrolled carbon dioxide emission from traditional coal-fired power plants. The aim of this dissertation is to critically analyse the future of the Nigerian coal power stations following the need to do carbon dioxide emission control necessary for ensuring a sustainable environment. Achieving this aim entails the appraisal of environmental regulation standards and cost structures of carbon dioxide (C02) emission reduction options for the coal power stations. Controlling carbon dioxide emission from existing coal power stations requires retrofit system that captures and effectively sequestrates the captured CO2. The cost and performance effect of the CO2 retrofit system on the existing power plant can be simulated with standard computer software models. In this study the lECM-cs computer modelling tool for power plants was used in determining the cost and performance impacts of applying an Amine-based C02 capture system to the Oji river power station in Nigeria. With the lECM-cs model, it was established that reducing C02 emission imposes an additional cost on the power plant which increases the unit cost of electricity generated. This additional cost index requires economic justification for its acceptance. This is due to the need to demonstrate its viability judging from the cost of electricity generated from other sources in the Nigerian economy. For the Oji river case, the station is old and requires extensive renovation. This causes a cost escalation over and above the cost associated with the CO2 sequestration system. As such, Oji coal power station does not have an economic future if C02 emission sequestration becomes obligatory. The future of coal power stations in Nigeria can be considered from two scenarios: one where the current national environmental standard is retained and another where it is revised. The revision classifies CO2 as a pollutant which makes its emission reduction imperative for coal power plants. Under the current standard, building modern large capacity pulverized coal-fired power plants with improved steam cycles should be encouraged. But with the review of the national standard, the focus should be on building new large capacity coal power stations with integrated CO2 emission control. This will ensure an environmentally friendly future for coal power stations in Nigeria. / Thesis (M.Ing. (Development and Management Engineering))--North-West University, Potchefstroom Campus, 2009.

Nigeria is presently being faced with a growing electricity demand problem following its population growth rate. The total installed capacity is far less than the current demand for electricity supply. As a way of bridging out this supply gap, the federal government is mobilizing all of its potential energy options. Coal is widely used for power generation in many countries. But today, the continued usage of coal for power generation is being challenged by the disturbing global warming phenomenon. This is due to the quantity of uncontrolled carbon dioxide emission from traditional coal-fired power plants. The aim of this dissertation is to critically analyse the future of the Nigerian coal power stations following the need to do carbon dioxide emission control necessary for ensuring a sustainable environment. Achieving this aim entails the appraisal of environmental regulation standards and cost structures of carbon dioxide (C02) emission reduction options for the coal power stations. Controlling carbon dioxide emission from existing coal power stations requires retrofit system that captures and effectively sequestrates the captured CO2. The cost and performance effect of the CO2 retrofit system on the existing power plant can be simulated with standard computer software models. In this study the lECM-cs computer modelling tool for power plants was used in determining the cost and performance impacts of applying an Amine-based C02 capture system to the Oji river power station in Nigeria. With the lECM-cs model, it was established that reducing C02 emission imposes an additional cost on the power plant which increases the unit cost of electricity generated. This additional cost index requires economic justification for its acceptance. This is due to the need to demonstrate its viability judging from the cost of electricity generated from other sources in the Nigerian economy. For the Oji river case, the station is old and requires extensive renovation. This causes a cost escalation over and above the cost associated with the CO2 sequestration system. As such, Oji coal power station does not have an economic future if C02 emission sequestration becomes obligatory. The future of coal power stations in Nigeria can be considered from two scenarios: one where the current national environmental standard is retained and another where it is revised. The revision classifies CO2 as a pollutant which makes its emission reduction imperative for coal power plants. Under the current standard, building modern large capacity pulverized coal-fired power plants with improved steam cycles should be encouraged. But with the review of the national standard, the focus should be on building new large capacity coal power stations with integrated CO2 emission control. This will ensure an environmentally friendly future for coal power stations in Nigeria. / Thesis (M.Ing. (Development and Management Engineering))--North-West University, Potchefstroom Campus, 2009.

One of the most significant goals in coal mining technology research is the automation of underground coal mining machinery. A current challenge with automating underground coal mining machinery is measuring and maintaining a coal mining horizon. The coal mining horizon is the horizontal path the machinery follows through the undulating coal seam during the mining operation. A typical mining practice is to leave a thin remnant of coal unmined in order to maintain geological stability of the cutting face. If the remnant layer is too thick, resources are wasted as the unmined coal is permanently unrecoverable. If the remnant layer is too thin, the product is diluted by mining into the overburden and there is an increased risk of premature roof fall which increases danger. The main challenge therefore is to develop a robust sensing method to estimate the thickness of thin remant coal layers. This dissertation addresses this challenge by presenting a pattern recognition methodology to estimate thin remnant coal layer thickness using ground penetrating radar (GPR). The approach is based upon a novel feature vector, derived from the bispectrum, that is used to characterise the early-time segment of 1D GPR data. The early-time segment is dominated by clutter inherent in GPR systems such as antenna crosstalk, ringdown and ground-bounce. It is common practice to either time-gate the signal, disregard the clutter by rendering the early-time segment unusable, or configure the GPR equipment to minimise the clutter effects which in turn reduces probing range. Disregarding the early-time signal essentially imposes a lower thickness limit on traditional GPR layer thickness estimators. The challenges of estimating thin layer thickness is primarily due to these inherent clutter components. Traditional processing strategies attempt to minimise the clutter using pre-processing techniques such as the subtraction of a calibration signal. The proposed method, however, treats the clutter as a deterministic but unknown signal with additive noise. Hence the proposed approach utilises the energy from the clutter and monitors change in media from subtle changes in the signal shape. Two complementary processing methods important to horizon sensing have been also proposed. These methods, near-surface interface detection and antenna height estimation, may be used as pre-validation tools to increase the robustness of the thickness estimation technique. The proposed methods have been tested with synthetic data and validated with real data obtained using a low power 1.4 GHz GPR system and a testbed with known conditions. With the given test system, it is shown that the proposed thin layer thickness estimator and near-surface interface detector outperform the traditional matched filter based processing methods for layers less than 5 cm in thickness. It is also shown that the proposed antenna height estimator outperforms the traditional height estimator for heights less than 7 cm. These new methods provide a means for reliably extending layer thickness estimation to the thin layer case where traditional approaches are known to fail.

No description available.

No description available.

No description available.

No description available.

Thesis (M.A.)--University of Tennessee, Knoxville, 2009. / Title from title page screen (viewed on Oct. 22, 2009). Thesis advisor: Sherry Cable. Vita. Includes bibliographical references.