At a time when global environmental change is posing a growing challenge to the world’s economy and creating uncertainties to livelihood of its inhabitants, Coal thermal power plants are under pressure to meet stringent environmental regulations into achieving worldwide set millennial goals for mitigating the effect of emission gases on the atmosphere. Owing to its abundance, it is unlikely to see the use of coal completely missing from the global energy mix within the next hundred years to come. While innovative emission reduction technologies are evolving for the better, trendy technological solutions which require reintegration of these coal plants with alternative greener fuels are growing at the moment. Among these solutions, the following paper investigates possible means for repowering a coal steam power plant with indirect solar heating solutions to boost its annual outputs. Two widely deployable solar thermal technologies, parabolic trough and Central tower receiver systems, are introduced at different locations in the steam plant to heat working fluid thereby enhancing the thermodynamic quality of steam being generated. Potential annual energy output was estimated using commercially available TRNSYS software upon mass and heat balance to every component of solar and steam plant. The annual energy outputs are weighed against their plant erecting and running costs to evaluate the economic vitality of the proposed repowering options. The results show that parabolic trough heating method could serve as the most cost effective method generating electricity at competitive prices than solar only powered SEGS plants. While cost may be acceptable in the unit of energy sense, the scale of implementation has been proven to be technically limited. / Kriel Power Plant

In Canada, coal-fired power plants are the largest anthropogenic point sources of atmospheric CO₂. The most promising near-term strategy for mitigating CO₂ emissions from these facilities is the post-combustion capture of CO₂ using MEA (monoethanolamine) with subsequent geologic sequestration. While MEA absorption of CO₂ from coal-derived flue gases on the scale proposed above is technologically feasible, MEA absorption is an energy intensive process and especially requires large quantities of low-pressure steam. It is the magnitude of the cost of providing this supplemental energy that is currently inhibiting the deployment of CO₂ capture with MEA absorption as means of combatting global warming. The steam cycle of a power plant ejects large quantities of low-quality heat to the surroundings. Traditionally, this waste has had no economic value. However, at different times and in different places, it has been recognized that the diversion of lower quality streams could be beneficial, for example, as an energy carrier for district heating systems. In a similar vein, using the waste heat from the power plant steam cycle to satisfy the heat requirements of a proposed CO₂ capture plant would reduce the required outlay for supplemental utilities; the economic barrier to MEA absorption could be removed. In this thesis, state-of-the-art process simulation tools are used to model coal combustion, steam cycle, and MEA absorption processes. These disparate models are then combined to create a model of a coal-fired power plant with integrated CO₂ capture. A sensitivity analysis on the integrated model is performed to ascertain the process variables which most strongly influence the CO₂ energy penalty. From the simulation results with this integrated model, it is clear that there is a substantial thermodynamic advantage to diverting low-pressure steam from the steam cycle for use in the CO₂ capture plant. During the course of the investigation, methodologies for using Aspen Plus?? to predict column pressure profiles and for converging the MEA absorption process flowsheet were developed and are herein presented.

In Canada, coal-fired power plants are the largest anthropogenic point sources of atmospheric CO₂. The most promising near-term strategy for mitigating CO₂ emissions from these facilities is the post-combustion capture of CO₂ using MEA (monoethanolamine) with subsequent geologic sequestration. While MEA absorption of CO₂ from coal-derived flue gases on the scale proposed above is technologically feasible, MEA absorption is an energy intensive process and especially requires large quantities of low-pressure steam. It is the magnitude of the cost of providing this supplemental energy that is currently inhibiting the deployment of CO₂ capture with MEA absorption as means of combatting global warming. The steam cycle of a power plant ejects large quantities of low-quality heat to the surroundings. Traditionally, this waste has had no economic value. However, at different times and in different places, it has been recognized that the diversion of lower quality streams could be beneficial, for example, as an energy carrier for district heating systems. In a similar vein, using the waste heat from the power plant steam cycle to satisfy the heat requirements of a proposed CO₂ capture plant would reduce the required outlay for supplemental utilities; the economic barrier to MEA absorption could be removed. In this thesis, state-of-the-art process simulation tools are used to model coal combustion, steam cycle, and MEA absorption processes. These disparate models are then combined to create a model of a coal-fired power plant with integrated CO₂ capture. A sensitivity analysis on the integrated model is performed to ascertain the process variables which most strongly influence the CO₂ energy penalty. From the simulation results with this integrated model, it is clear that there is a substantial thermodynamic advantage to diverting low-pressure steam from the steam cycle for use in the CO₂ capture plant. During the course of the investigation, methodologies for using Aspen Plus® to predict column pressure profiles and for converging the MEA absorption process flowsheet were developed and are herein presented.

Manure-based biomass (MBB) has the potential to be a source of green energy at large coal-fired power plants and on smaller-scale combustion systems at or near confined animal feeding operations. Although MBB is a low quality fuel with an inferior heat value compared to coal and other fossil fuels, the concentration of it at large animal feeding operations can make it a viable source of fuel. Mathematical models were developed to portray the economics of co-firing and reburning coal with MBB. A base case run of the co-fire model in which a 95:5 blend of coal to low-ash MBB was burned at an existing 300-MWe coal-fired power plant was found to have an overall net present cost of $22.6 million. The most significant cost that hindered the profitability of the co-fire project was the cost of operating gas boilers for biomass dryers that were required to reduce the MBB's moisture content before transportation and combustion. However, a higher dollar value on avoided nonrenewable CO2 emissions could overrule exorbitant costs of drying and transporting the MBB to power plants. A CO2 value of $17/metric ton was found to be enough for the MBB co-fire project to reach an economic break-even point. Reburning coal with MBB to reduce NOx emissions can theoretically be more profitable than a co-fire project, due to the value of avoided NOx emissions. However, the issue of finding enough suitable low-ash biomass becomes problematic for reburn systems since the reburn fuel must supply 10 to 25% of the power plant?s heat rate in order to achieve the desired NOx level. A NOx emission value over $2500/metric ton would justify installing a MBB reburn system. A base case run of a mathematical model describing a small-scale, on-the-farm MBB combustion system that can completely incinerate high-moisture (over 90%) manure biomass was developed and completed. If all of the energy or steam produced by the MBB combustion system were to bring revenue to the animal feeding operation either by avoided fueling costs or by sales, the conceptualized MBB combustion system has the potential to be a profitable venture.

No description available.

Thesis (MPhil (Public Management and Planning))--University of Stellenbosch, 2010. / ENGLISH ABSTRACT: South Africa has a mean annual precipitation far lower than the global average. This is a fundamental constraint to development, especially when the country has already run out of surplus water and dilution capacity. To add further pressure, southern Africa’s water resources are expected to decrease as a result of climate change. Despite the potential devastation, the country’s response to climate change has been limited. South Africa’s energy sector is dominated by coal power stations and is the country’s primary emitter of carbon dioxide. Given the significantly higher water usage of coal-fired power plants compared to that of most renewable energy power plants, the transition to a clean energy infrastructure might be more successfully motivated by water scarcity than by the promise of reduced carbon emissions. This article analyses more critically the impact of coal-fired electricity generation on South Africa’s water resources, by estimating a water-use figure that extends backwards from the power plant to include water used during extraction of the coal. This figure can then be compared to the water usage of alternative electricity generation options. It is then possible to estimate how much water could be saved by substituting these alternatives in place of additional coal-fired plants. / AFRIKAANSE OPSOMMING: Suid-Afrika se gemiddelde jaarlikse neerslag is baie laer as die wêreldwye gemiddelde. Dit plaas ’n wesenlike beperking op ontwikkeling, veral aangesien die land se surplus water- en verdunningskapasiteit reeds uitgeput is. Om die saak verder te vererger, word verwag dat Suidelike Afrika se waterbronne gaan kleiner word as gevolg van klimaatsverandering. Ten spyte van die potensiële ramp, was die land se reaksie op klimaatsverandering tot dusver baie beperk. Steenkoolkragstasies, wat Suid-Afrika se energiesektor oorheers, is die land se primêre bron van koolstofdioksieduitlating. Gegewe die beduidend hoër waterverbruik van steenkoolkragstasies teenoor dié van die meeste kragstasies wat met hernubare energie werk, kan die verandering na ’n skoonenergie-infrastruktuur meer suksesvol gemotiveer word deur waterskaarste as deur die belofte van verminderde koolstofuitlatings. Hierdie artikel analiseer die impak van steenkoolgedrewe elektrisiteitsopwekking op Suid-Afrika se waterbronne meer krities deur te beraam hoeveel water verbruik word van die kragstasie terug tot by die ontginning van die steenkool. Hierdie syfer kan dan vergelyk word met die waterverbruik van alternatiewe kragopwekkingsopsies. Dit is dan moontlik om te beraam hoeveel water gespaar kan word deur hierdie alternatiewe op te rig in plaas van bykomende steenkoolkragstasies.

This research has developed a novel sustainability assessment framework for electricity technologies and scenarios, taking into account techno-economic, environmental and social aspects. The methodology uses a life cycle approach and considers relevant sustainability impacts along the supply chain. The framework is generic and applicable to a range of electricity technologies and scenarios. To test the methodology, sustainability assessments have been carried out first for different technologies and then for a range of possible future electricity scenarios for the UK. The electricity options considered either contribute significantly to the current UK electricity mix or will play a greater role in the future; these are nuclear power (PWR), natural gas (CCGT), wind (offshore), solar (residential PV) and coal power (subcritical pulverised). The results show that no one technology is superior and that certain tradeoffs must be made. For example, nuclear and offshore wind power have the lowest life cycle environmental impacts, except for freshwater eco-toxicity for which gas is the best option; coal and gas are the cheapest options, but both have high global warming potential; PV has relatively low global warming potential but high cost, ozone layer and resource depletion. Nuclear, wind and PV increase certain aspects of energy security but introduce potential grid management problems; nuclear also poses complex risk and intergenerational questions. Five potential future electricity mixes have also been examined within three overarching scenarios, spanning 2020 to 2070, and compared to the present-day UK grid. The scenarios have been guided by three different approaches to climate change: one future in which little action is taken to reduce CO2 emissions (‘65%’), one in which electricity decarbonises by 80% by 2050 in line with the UK’s CO2 reduction target (‘80%’), and one in which electricity is virtually decarbonised (at the point of generation) by 2050, in line with current policy (‘100%’).In order to examine the sustainability implications of these scenarios, the assessment results from the present-day comparison were projected forward to describe each technology in future time periods. Additional data were compiled so that coal with carbon capture and storage (CCS) – a potentially key future technology – could be included. The results of the scenario analyses show that the cost of generating electricity is likely to increase and become more capital-intensive. However, the lower-carbon scenarios are also at least 87% less sensitive to fuel price volatility. Higher penetration of nuclear and renewables generally leads to better environmental performance and more employment, but creates unknown energy storage costs and, in the case of nuclear power and coal CCS, the production of long-lived waste places a burden of management and risk on future generations. Therefore, the choice of the ‘most sustainable’ electricity options now and in the future will depend crucially on the importance placed on different sustainability impacts; this should be acknowledged in future policy and decision making. A good compromise requires strategic government action; to provide guidance, specific recommendations are made for future government policy.

I denna avhandling studeras en ny teknik för att hantera växthuseffekten. Den nya tekniken heter koldioxidavskiljning och lagring (CCS) och granskades av FN:s klimatpanel 2005 och tillskrevs då möjligheterna att stå för 15-55% av alla CO2-reducering fram till 2100 och detta till en 30% lägre kostnad än vad som annars vore möjligt. EU är en framträdande pådrivare av CCS och för fram att växthuseffekten inte kan hanteras utan att CCS implementeras skyndsamt. CCS beskrivs i dessa sammanhang som en hållbar teknik. CCS är emellertid förbunden med långtidslagring, en betydande teknisk komplexitet och tillämpas främst på kolkraftverk. Storskaliga satsningar på CCS kan medföra att kolanvändningen ökar. Syftet med avhandlingen är att analysera de vetenskapliga och politiska ansträngningarna att visa att CCS är en eftersträvansvärd teknik för att hantera växthuseffekten. Utifrån perspektivet ekologisk modernisering och genom granskning av studier av vetenskapliga rapporter, artiklar i massmedia, politiska dokument och intervjuer genomförs studien. Scenerier och prognoser har en central funktion för att kunna påvisa att CCS är en eftersträvansvärd teknik. I flera av dessa scenarier framställs en närmast linjär teknikutveckling och flera betydelsefulla problem och hinder bortses från. CCS framstår som en teknik med stor teknisk och ekonomisk potential och i massmedia beskrivs CCS ofta som oumbärlig. En mer nyanserad bild framträder vid intervjuer med CCS-experter då fler osäkerheter och hinder lyfts fram. Förståelsen för varför denna teknik för stöd av många starka aktörer blir även tydligare. Den dominerande beskrivningen av CCS egenskaper och inverkan på energisystemen ligger i linje med det som är utmärkande för den ekologiska modernisering och således även för det dominerande sättet att bedriva energi- och klimatpolitik idag. / In this dissertation an emerging technology to manage climate change is studied. The technology is carbon dioxide capture and storage (CCS) and was reviewed by the IPCC in 2005. IPCC claims that CCS could contribute 15–55% to the cumulative mitigation effort worldwide until 2100 and reduce the costs of stabilizing CO2 concentrations by 30%. The EU promotes CCS and believes that climate change cannot be managed unless CCS is promptly implemented. In this context CCS is labelled as a sustainable technology. However CCS deals with long-term waste disposal, a significant technological complexity and is meant to be installed mainly in coal-fired power plants. Large scale implementation of CCS might lead to a rise in coal usage and concerns are raised this will impede the development of renewable energy. The aim of this dissertation is to analyze the scientific and political efforts to show that CCS is a rational and viable solution to the climate change problems. The study is conducted from the perspective of ecological modernization and is undertaken through a review of scientific reports, mass media articles, political documents and interviews. Scenarios and prognoses have a central position in making a future of large-scale CCS implementation plausible: through the scenarios, a linear development trend is visualized in which technological and scientific problems are assumed to be solved as CCS is implemented. CCS is described as a technology with substantial potential and is in the mass media often pictured as indispensable. A more nuanced picture appears when analyzing interviews with CCS-experts. The understanding of why this technology is supported by several influential actors is deepened. The dominating description of CCS and impact on the energy systems is compatible to the characteristics of ecological modernization and thus also to the predominating way of practising energy and climate politics today.

Today’s carbon constrained world with its increasing demand for cheap energy and a fossil fuel intensive fleet of power producers is making carbon capture and storage (CCS) desirable. Several CCS technologies are under investigation by various research and development groups globally. One of the more promising technologies is oxy-fuel combustion, since it produces a CO2 rich flue gas which requires minor processing to meet storage condition requirements. In this study the economics of an advanced super critical oxy-coal power plant burning lignite, simulated in-house was assessed. A robust and user-friendly financial tool box has been developed with commonly acceptable default parameter settings. Capital, operation and maintenance costs were estimated along with corresponding levelized cost of electricity and CO2 avoidance costs calculated using the detailed financial model developed. A levelized cost of electricity of 131 $/MWhrnet along with a levelized CO2 avoidance cost of 64 $/tonne was estimated for an ASC oxy-coal power plant with CO2 capture. Also a levelized cost of electricity of 83 $/MWhrnet was estimated for an ASC air-fired coal power plant without CO2 capture capabilities as the base plant. The price of electricity was observed to increase from 83 $/MWhrnet to 131 $/MWhrnet translating into a 57% increase. The sensitivity of the overall economics of the process was assessed to several parameters. The overall economics was found sensitive to the choice chemical engineering plant cost index (CEPCI), capacity factor, size of power plant, debt ratio, fuel price, interest rate, and construction duration.

Today???s carbon constrained world with its increasing demand for cheap energy and a fossil fuel intensive fleet of power producers is making carbon capture and storage (CCS) desirable. Several CCS technologies are under investigation by various research and development groups globally. One of the more promising technologies is oxy-fuel combustion, since it produces a CO2 rich flue gas which requires minor processing to meet storage condition requirements. In this study the economics of an advanced super critical oxy-coal power plant burning lignite, simulated in-house was assessed. A robust and user-friendly financial tool box has been developed with commonly acceptable default parameter settings. Capital, operation and maintenance costs were estimated along with corresponding levelized cost of electricity and CO2 avoidance costs calculated using the detailed financial model developed. A levelized cost of electricity of 131 $/MWhrnet along with a levelized CO2 avoidance cost of 64 $/tonne was estimated for an ASC oxy-coal power plant with CO2 capture. Also a levelized cost of electricity of 83 $/MWhrnet was estimated for an ASC air-fired coal power plant without CO2 capture capabilities as the base plant. The price of electricity was observed to increase from 83 $/MWhrnet to 131 $/MWhrnet translating into a 57% increase. The sensitivity of the overall economics of the process was assessed to several parameters. The overall economics was found sensitive to the choice chemical engineering plant cost index (CEPCI), capacity factor, size of power plant, debt ratio, fuel price, interest rate, and construction duration.