Thesis (Ph. D.) -- University of Tennessee, Knoxville, 2006. / Title from title page screen (viewed on Jan. 31, 2007). Thesis advisor: Paul R. Bienkowski. Vita. Includes bibliographical references.

Climate change is one of the greatest and probably most challenging environmental, social and economical threats facing the world this century. Human activities have altered the chemical composition of the atmosphere through the buildup of significant quantities of greenhouse gases (GHGs), which remain in the atmosphere for long periods of time and intensify the natural greenhouse effect. Increasing concentrations of greenhouse gases, mainly CO2, are likely to accelerate the rate of climate change. Concerns are growing about how increases in CO2 caused by human activities are contributing to the natural greenhouse effect and raising the Earth's average temperature. Electricity generation, especially from fossil fuel, and petroleum industries contribute the most to greenhouse gases emissions in Canada. As of 2004, they contributed to about 37% of total (GHGs). Risks of climate change and subsequent future environmental regulations are pressing electricity and petroleum refining industries to minimize their greenhouse gas emissions, mainly CO2. Fossil fuel power plants and refineries are now being challenged to comply with the Kyoto protocol by the United Nations Framework Convention and Climate Change (UNFCC). Canada’s target is a reduction in CO2 emissions of 6% from 1990 level. In this thesis, an optimization approach for integrating planning and CO2 reduction is developed for electricity and refinery sectors. Three different CO2 mitigation options are considered in each case. For the electricity sector, these mitigation options were 1) fuel balancing (optimal adjustment of the operation of existing generating stations to reduce CO2 emissions without making structural changes to the fleet), 2) fuel switching (switching from carbon intensive fuel to less carbon intensive fuel, essentially switching from coal to natural gas) and 3) implementing different technologies for efficiency improvement. The optimization model takes into account meeting electricity demand and achieving a certain CO2 reduction target at a minimum overall cost. The model was formulated as a Mixed Integer Non Linear Program (MINLP) and was implemented in GAMS (General Algebraic Modeling System). Exact linearization techniques were employed to facilitate solution development. The computer program was capable of determining the best strategy or mix of strategies to meet a certain CO2 reduction target at minimum cost. The model was illustrated on a case study for Ontario Power Generation (OPG) fleet. The results showed that for 1% CO2 reduction target, only fuel balancing need to be applied and even a decrease of about 1.3% in overall cost was obtained. The optimizer chose to increase production from all non fossil fuel power plants and to decrease production from natural gas power plant. This is because natural gas is the most expensive fuel that OPG uses. For higher reduction targets, it was necessary to implement fuel switching. For 30% reduction, for example, 11 boilers out of 27 (4 are already natural gas) are switched from coal to natural gas and the cost increases by about 13%. Applying efficiency improvement technologies such as installing new turbine blades was a good option only at small reduction targets. As the reduction target increases, the optimizer chose not to implement efficiency improvement technologies and only fuel switching was the best option to select in addition to fuel balancing. For the refinery sector, a similar strategy was applied. An optimization model was developed to maximize profit from selling final products and to meet a given CO2 reduction target with products demand and specifications. Three CO2 mitigation options were considered and these were: 1) balancing that implies the increase in production from units that emit less CO2 emissions provided that demand is met, 2) fuel switching that involves switching from current carbon intensive fuel to less carbon intensive fuel such as natural gas, 3) implementation of CO2 capture technologies. Chemical absorption (MEA) process was used as the capture process. Prior to the development of the refinery planning model, a sub-model was developed for each unit in a refinery layout. Then, the sub-models were integrated into a master planning model to meet final products demand and specifications with the objective of maximizing profit without CO2 mitigation options. The model was solved first as a Non Linear Program (NLP). Then, binary variables representing the existence or no existence of fuel switching option and CO2 capture processes were introduced into the model. The model was formulated as a Mixed Integer Non Linear Program (MINLP), coded in GAMS, and applied to different case studies. The results showed that the refinery planning model tends to produce more from the most profitable product, which is gasoline, and chose to blend products into the most profitable pool unless the demand needs to be satisfied for certain other products. The model, for example, chose to send kerosene from the diesel hydrotreater to the kerosene pool and not to the diesel pool since kerosene has higher selling value than diesel. When CO2 mitigation options were introduced into the model, only 0.4% CO2 reduction was achieved by simply decreasing production from the hydrocracker (HC) unit and increasing production from the fluidized catalytic cracking (FCC) unit. This was done because the FCC unit tends to emit less CO2 compared to the HC unit. At higher reduction target such as 1%, fuel switching was implemented by choosing the FCC to run with natural gas. The profit decreased slightly because of the retrofit cost of switching. It was noticed also that fuel switching can achieve a maximum of 30% reduction in CO2 emissions. This was achieved by switching all units to run with natural gas that emits less CO2 emissions. For a reduction target higher than 30%, CO2 capture technologies need to be applied. For 60% reduction, the optimization chose to switch three units (out of 8) and to capture CO2 emissions coming from four units. Only the FCC remained unchanged. A decrease in the profit was noticed as the reduction target increases since more units need to be switched and more CO2 need to be captured. The results showed that adding sequestration cost further decreased the profit. However, it was noticed that the selling price of final products had the most effect on the profit. An increase of 20%, for example, in final products’ prices, leads to a 10% increase in profit even when the CO2 reduction target was as high as 80%. When the retrofit cost for switching and capture was decreased by 30%, the effect on the profit was noticed only at higher reduction targets since more units were switched and more CO2 capture units were implemented

Thesis (M.S.)--West Virginia University, 2001. / Title from document title page. Document formatted into pages; contains xii, 102 p. : ill. (some col.). Vita. Includes abstract. Includes bibliographical references (p. 80-81).

Thesis (M.S.)--West Virginia University, 2004. / Title from document title page. Document formatted into pages; contains xii, 161 p. : ill. (some col.), maps (some col.). Includes abstract. Includes bibliographical references (p. 132-137).

Thesis (M. Sc.)--University of Hong Kong, 1996. / Includes bibliographical references.

Thesis (M.S.)--Central Connecticut State University, 2002. / Thesis advisor: Robert Fischbach. " ... in partial fulfillment of the requirements for the degree of Master of Science in Organizational Communications." Includes bibliographical references (leaves 86-90). Also available via the World Wide Web.

Recent droughts and heat waves have revealed the vulnerability of some power plants to effects from higher temperature intake water for cooling. Climate projections estimate higher air temperatures in future years, indicating that these problems could increase. This research seeks to understand the magnitude of influence that higher temperatures will have on power plant effluent water temperatures to quantify a power plant's exposure to risk of de-rating induced by low or warm cooling water availability. The objective of this analysis is to help policymakers and plant operators plan for future electricity supplies without damaging the natural environment of the cooling reservoirs and rivers. This objective is met via assessment of water constraints associated with current technology, policy, and environmental conditions in two river basins, the Gulf Coast Basin in Texas and the Upper Mississippi River Basin in the Midwestern United States. Risk of reduced operations at these power plants associated with thermal discharge limits is then assessed by estimating intake and effluent water temperatures and comparing these estimates to current restrictions. Of the thirty-three plants analyzed, none are estimated to exceed effluent temperature limits within the study period of 2015 to 2035. However, twelve power plants could face increasing intake temperatures, leading to potential issues with cooling efficiency. Fourteen plants could discharge slightly higher effluent temperatures, possibly influencing the ecosystem of the return water body upon discharge beyond today's impacts. To help with planning for future issues, this analysis also identifies many of the ways by which power plants mitigate issues with low water levels and high temperatures. Designing plants for potentially scarce water resources and making policies that protect water supplies and support energy resources could be beneficial in coming years. This research is intended to inform that objective. / text

published_or_final_version / Radioisotope / Master / Master of Philosophy

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