Carbon Capture Technology

Transcription

1 Carbon Capture Technology A Technoeconomic Evaluation of Absorption, Gasification, and Oxy-Coal Combustion for Coal Power Plants Will Backus 12/17/2010

2 Table of Contents Executive Summary.. 2 Introduction 3 Sequestration 4 Absorption.. 5 Gasification 8 Oxy-Coal Combustion. 9 Case Study Outline Analysis 12 Energy Efficiency.. 12 Cost of Electricity. 13 Environmental Impact Special Cases.. 15 Retro-Fitting 17 Conclusion 17 References 20 Page 1

3 Executive Summary This report examines three different methods of carbon dioxide (CO 2 ) capture for carbon capture and sequestration (CCS) systems for coal fired power plants. The purpose of this report is to compare the three distinct technologies for overall feasibility of large scale implementation on standard coal power plants. Many political and economic reasons have forced industries, including the electric power sector, to move towards adopting greener technologies as CO 2 has been recognized as a green house gas (GHG), and therefore potentially environmentally harmful. Coal power plants with CCS lower CO 2 emissions up to 90%, but their adoption relies on being able to maintain efficiency and low costs for power plant owners. The three carbon capture (CC) technologies examined in a case study of 7 different potential CC systems were: -Absorption -Gasification -Oxy-coal combustion CO 2 absorption by the standard solvent MEA was found to be very energy consumptive, therefore leading to the highest Cost of Electricity (COE) and Mitigation Cost (MC) for any of the 7 cases. Newer technologies such as Integrated Gasification and Combined Cycle (IGCC) and Oxy-coal combustion power plants offer higher efficiencies and therefore better potential as CC sources. Oxycoal combustion has yet to be scaled up from pilot plant prototypes, but improvements to its design through more efficient Air Separator Unit (ASU) development are possible. An IGCC power plant with 80% CO 2 capture performed best due to its relatively low Energy Penalty (EP), COE, and MC. However, research should be continued for both gasification and oxy-coal combustion to determine which design is ultimately more feasible for large scale implementation. Page 2

4 Introduction The Intergovernmental Panel on Climate Change (IPCC) has recognized that the continuous release of CO 2 emissions at the gigaton level is likely to affect the climate. ii While the direct affect of CO 2 on the environment is still unclear, global and national limits on its release including the Kyoto Protocol call for reduced Green House Gas (GHG) emissions. The European Union uses a cap and trade approach to reducing CO 2 levels where an overall quota for carbon dioxide emissions is set and private companies are allowed to buy and trade the right to release CO 2. Furthermore, some countries such as Norway further tax the release of carbon dioxide to encourage reductions. On top of these direct governmental imposed economic incentives, the reduction of GHG levels is important because the effects of climate change are predicted to shave off anywhere from 1 to 12% of GDP in many countries due to shifting climate zones, floods, droughts, and rising sea levels. xiii While moving to alternative carbonless forms of energy such as wind and solar power offer a promising future, at best they can be projected to contribute 20% of U.S. energy within the next years because of economic barriers. viii Carbon dioxide emissions comprise 77% of total anthropogenic (man-made) GHG emissions with 38 gigatonnes (Gt) released in the year xx Over 98% of CO 2 emissions come from the combustion of fossil fuels including coal, natural gas, and petroleum. xxi More specifically, the combustion of coal makes up 33% of total energy related CO 2 emissions and 81% of CO 2 emissions from the electric power sector in the United States. xxi So clearly, fossil-fuel, and more specifically coal, power plants become a target for CO 2 reduction. Carbon capture and sequestration (CCS) is the main technology talked about to combat this problem. CO 2 is taken out of the gases produced from coal combustion (flue gas), concentrated, and stored somewhere underground so that it does not escape into the Earth s atmosphere. There are three basic categories of carbon capture systems and various ways to store the CO 2 once it has been captured. Post combustion capture is the most widely used today, employing the selective absorption of CO 2 from the flue gas into a chemical solvent. The second is pre-combustion gasification, where coal is gasified to Page 3

5 form synthesis gas (CO + H 2 ) and CO 2 can be separated before the hydrogen gas is burned as fuel. Oxyfuel combustion burns coal in pure oxygen instead of air, resulting in relatively easy to separate components of water vapor and CO 2 in the flue gas stream. Once the CO 2 has been captured, itmust be stored. Many studies have shown that CO 2 can be stored in underground geologic formations, deep sea saline aquifers, or can be reused in industrial processes. xxii Carbon capture technologies are still relatively new for implementation in the energy sector, although the idea has been around for decades. At present, no full-scale CO 2 capture systems have been used on coal power plants, and very few are in place for cleaner-burning natural gas power plants. This report takes a comprehensive look at the aforementioned technologies and their overall feasibility for large-scale application to coal fired power plants. The mechanisms and processes of the three options are described and then evaluated for their efficiencies of design and capture. Several cases are used to compare their economic viabilities. The numbers used for comparison are fairly standard, including the Energy Penalty (energy lost to CO 2 capture), Cost of Electricity, and Mitigation Cost ($/tonne CO 2 captured). Sequestration Carbon dioxide sequestration is ultimately the key to making carbon capture technologies a possibility. Concentrated CO 2 is pumped underground into sealed, naturally occurring geological formations, theoretically remaining there indefinitely. The best example of CO 2 sequestration is the Sleipner natural gas power plant owned by Statoil in Norway that has pumped over 1 million tons of highly pressurized CO 2 annually into sealed porous undersea sediments since xiii Figure 1 shows several of the methods for sequestration, including saline aquifers, depleted oil and gas reserves, and enhanced oil recovery, which has the potential of increasing petroleum yields. Studies have shown successful subterranean storage of CO 2, but the long term effects are not fully understood. The largest Page 4

6 fear is leakage over time, and economically modeling the leakage effects is only in very early stages. ix However, literature suggests that sequestration is a practical technology, with minimal amounts of CO 2 expected to release over time. i Regardless, one huge hurdle for CCS remains public acceptance. Therefore, further investigation of the effects of pumping CO 2 underground is needed. Fig. 1 CO 2 Sequestration Options xxiii Absorption Absorption is defined as the physical or chemical transfer of the concentration of an atom or molecule from one phase into another. Because coal is burned with air, which is 79% relatively inert nitrogen by volume, carbon dioxide is not the primary constituent in the flue gas. In fact, when coal is combusted, the flue gas is full of many different molecules, including toxic sulfur dioxide, nitrogen oxides, water vapor, carbon monoxide and dioxide, and particulate matter. A typical coal power plant combusts coal to form a gas stream that is 14% CO 2 by volume, so the absorption of CO 2 has to be highly selective in order to only absorb CO 2 out of the flue gas. Page 5

7 The standard solvent used for CO 2 chemical absorption is a 30% Monoethanolamine (MEA) solution. Physical absorption solvents will be brought up in the gasification section, as they are used to absorb CO 2 more effectively at higher pressures. In an aqueous solution, MEA acts as a weak base, which is capable of neutralizing the acidic molecule CO 2. The reaction forms a carbamate molecule as shown below. 2CH 2 CH 2 (OH)NH 2 +CO 2 =CH 2 CH 2 OH-NH 3 + +CH 2 CH 2 OH-NHCOO - (1) Two moles of MEA are required to absorb CO 2 through this reaction, leading to a theoretical loading capacity of 0.5 (mole CO 2 /mole solvent). In general, higher loading capacities are preferred in solvents and lead to more efficient capture results. Organic chemical properties such as substituted hydroxyl groups near the amine and other secondary pathways contribute to higher loading capacities, such as the CO 2 hydration xiv, xv pathway to form bicarbonate shown below. R 1 R 2 R 3 N+ CO 2 + H 2 O=HCO R 1 R 2 R 3 NH + (2) The process flow scheme of a typical amine-based capture system is shown in Figure 1. xiv,xv Flue gas entering the process at close to atmospheric pressure is cooled to the required operating temperature around The lean solvent (i.e. solvent with low content of CO 2 ) is pumped into an absorption tower to contact with cooled flue gas. The CO 2 is absorbed in the solvent, forming carbamate and other molecules, and the CO 2 clean flue gas exits the top of the absorber and vents to the atmosphere. Rich solvent (i.e. high content of CO 2 ) exiting the bottom of the absorber tower is then pumped to the top of the stripper tower. The stripper tower typically operates at and at higher pressure than the absorber, leading to the reverse reaction of Eq CO 2 is released from the stripper tower, and is condensed for storage. The lean solvent is cooled by the heat exchanger and recycled back to the Absorber Tower. Typically, 75-90% of the CO 2 is captured using this technology, producing nearly pure CO 2 (>99%) product stream. xvi Page 6

8 Figure 2: Chemical Absorption and Desorption Process for Cyclic CO 2 Capture and Release xvii MEA is a good solvent for CO 2 absorption for several reasons, including its high ph, CO 2 absorption capacity, and availability. However, MEA presents several problems as a solvent on a large scale as well, mainly solvent loss due to evaporation and corrosion. MEA will react with oxygen in excess to create toxic degradation products that will lower plant efficiencies over time. xix MEA captures 90% of CO 2 from coal power plants, but requires a large energy investment to do so. The largest losses come from solvent regeneration, where 4.2 GJ/tonne CO 2 captured are required to heat and cool the amine solution during its cycle in the desorption process. xx It is worth noting that much research has been put into finding other viable solvents for CO 2 absorption, including amino-acid salt solutions. The absorption of CO 2 into amino-acid salts is chemically very similar to that of MEA, but as an emerging design, there are currently several issues for using amino acid salt solutions on an industrial scale. The biggest obstacle is that amino acid salt solutions require a membrane placed in between the solvent and the flue gas, which would reach extremely large dimensions for full-scale capture. The economics of this kind of absorption are compared to that of MEA later, but are rough estimates as only small scale CO 2 capture has been demonstrated to date. Page 7

9 Gasification Coal gasification technology has been around for hundreds of years. In the 1800 s coal was burned to create a gas composed mainly of carbon monoxide (CO) and hydrogen (H 2 ) called synthesis gas (syngas) used for powering homes and buildings until technology for extracting natural gas came about. vi The design changes to make it usable as a CO 2 capturing device including pre-combustion CO 2 absorption solvents are already available, but no commercial coal fired power plant using gasification captures CO 2. Coal gasification occurs by heating coal to high temperatures, pressurizing it, and then flushing oxygen and water vapor across it. Coal gets oxidized by the oxygen and water to form syngas by the reaction below: x 3C (i.e., coal) + O 2 + H 2 O H 2 + 3CO (3) Typically, some of the coal is also fully combusted to CO 2. In order to fully capture the carbon product from the coal, the water gas shift reaction is employed to get a final product of carbon dioxide and hydrogen gas: CO + H 2 O CO 2 + H 2 (4) The hydrogen gas can then be used as an energy source, while the CO 2 can be easily selectively absorbed at its high concentration in the gas stream using physical solvents such as Selexol. Selexol absorbs CO 2 effectively only at high pressures (~300 psi), and it has been proven to be more effective than MEA and other solvents at the kinds of pressures that exist after the gasification process which produces a gas stream of higher CO 2 concentration than a traditional coal combustion with air. Coal power plants using gasification are generally called Integrated Gasification and Combined Cycle (IGCC) power plants. The combined cycle is a steam turbine cycle re-using waste heat from the gasification of coal in order to increase energy efficiency. In this way, energy is produced from two processes: the combustion of hydrogen gas and the steam turbine cycle. Figure 3 shows an outline of the process of an IGCC plant. Coal and air are input, some of the oxygen is stripped from air in order to Page 8

10 gasify the coal, and then the CO 2 and other unnecessary products (such as sulfur dioxide) are separated and captured. As can be seen in the diagram, power production comes from the two turbines, one for combustion and one for steam. In order for an IGCC to work with carbon capture, some of the additions would be oxygen production, a shift reactor (for the water gas shift reaction), and a solvent absorption tower for the Selexol process. iv In order for this to be a completely viable form of energy production, hydrogen powered turbines would need to be improved. Because of the high combustion temperature of H 2, existing turbines can only accept gas containing 45% H 2, but higher efficiencies would be achievable if the gas stream could burn a fuel more concentrated in H 2. Figure 3: IGCC Process xxiv Oxy-Coal Combustion In a conventional coal combustion power plant, air and coal are supplied to a furnace where the oxygen in the air is combusted with coal in order to produce heat. The nitrogen in air moderates the furnace temperatures and facilitates heat transfer for steam production which spins the steam generators producing electricity. iii Because air is composed of 79% relatively inert Nitrogen, the flue gas is only 14% CO 2 and must be separated by selective and energy intensive amine or membrane processes (as discussed in the absorption section). However, the combustion of coal in pure oxygen creates a flue Page 9

11 gas highly concentrated in CO 2 and H 2 O, therefore making separation much more energy efficient. Theoretically, the CO 2 concentration could reach close to 80% due to the atomic makeup of coal, but because the heat of combustion of pure oxygen is so high, some of the combusted coal gas (CO 2 and H 2 O) must be recycled in order to moderate temperature as the Nitrogen in air would do normally. iii The combusted coal gas that is not recycled can then be separated to get pure CO 2 by a distillation tower. In the distillation tower, the flue gas is cooled to around -56ᵒ F in order to condense out the excess O 2 and H 2 O, thereby creating a product extremely concentrated in CO 2 for capture that can be condensed and collected. ii This process is much less energy intensive than absorption processes required for MEA and Selexol CO 2 absorption. Figure 4 shows a flow chart for the inputs and outputs of oxy-coal combustion. The biggest challenge to making oxy-coal combustion on an industrial scale is the Air Separation Unit (ASU), which intakes air and separates O 2 from N 2. ii An ASU is also needed for IGCC plants in order to get pure oxygen to gasify coal; however, less oxygen is required for gasification than combustion so an ASU for a full scale oxy-coal combustion power plant would need to be much larger. Presently, ASU s have reached sizes capable of producing 4200 tons per day (tpd) O 2. This is adequate for a 500 MW IGCC power plant s needs, but for a 500MW oxy-coal plant, roughly 10,300 tpd O 2 would be required. v Figure 4: Oxy-Coal Combustion Process iv Page 10

12 Case-Study Several cases for different kinds of coal power plants were examined to compare their theoretical full scale performances. All technologies were based on the specs for an average size US coal power plant (close to 550 MW). Two baselines were used to compare efficiencies. The first was a traditional pulverized coal combustion power plant with no carbon capture (550 MW output), and the second was an IGCC power plant with no carbon capture (577MW output), the industry standard for new coal power plant design. For cases 1-3, numbers and assumptions were taken from studies from ii,iv Babcock and Wilcox, while for cases 4-6, numbers were taken from Ordorica-Garcia et al. Case 1: -MEA Absorption with 90% CO 2 capture (standard capture rate for MEA absorption systems) on a standard pulverized coal power plant. Case 2: -Super Critical (SC) Oxy-coal combustion (242 bar, F). Super critical combustion operates at pressures above the critical point of water, meaning water exists as a super-critical fluid instead of separated phases of liquid and vapor. Operating at higher temperatures and pressures allows for higher plant efficiencies. -95% molar O 2 fed in for combustion (not pure, but more economically viable than pure >99% molar O 2 ) -550 MW power output -Design assumed to be put in place ; however, current design of ASU s was used in calculating costs (improvement on ASU design by this time is likely due to research and development) Case 3: -Ultra Super Critical (USC) Oxy-coal combustion (270 bar, F). Ultra super critical combustion is the same idea as SC combustion, just at even higher pressures and temperatures. This kind of combustion is still not completely understood, as proper materials for combustion chambers at such extreme conditions are still under experimentation. xi -All other specifications the same as Case 2 Case 4: -IGCC with 80% CO 2 capture -Power output is 488 MW Case 5: -IGCC with 60% CO 2 capture -Power output is 512 MW Page 11

13 % efficient Case 6: -IGCC with CO 2 and H 2 S (sulfur dioxide) Co-capture. CO 2 and H 2 S are removed from the flue gas simultaneously using a single absorption process. Normally H 2 S must be captured separately during coal combustion because it is a monitored toxic compound, so combining H 2 S capture with CO 2 capture means only one acid gas absorber needs to be built instead of two. Case 7*: -CO 2 absorption with CORAL solvents (brand of a specific amino-acid salt solution developed by private European research group, TNO). CORAL stands for CO 2 Removal Absorption Liquid. * Cost of electricity and overall plant efficiency could not be ascertained. xix Analysis: Energy Efficiency: Not surprisingly, the worst plant efficiency is that with MEA absorption. Plant efficiency is defined as the percent of energy stored in the fuel source (coal) that is ultimately converted to electricity. The large energy losses due to the heat required for solvent regeneration are by far the most costly, making MEA absorption a highly unfeasible technology. The Energy Penalty (percent of total input fuel that must be used to CC processes, EP) for MEA is 23%, which is the highest EP for all cases examined Graph 1: Plant Efficiency Page 12

14 Graph 1 shows several options, particularly USC oxy-fuel and all IGCC cases with carbon capture, offer comparable plant efficiencies to that of a conventional pulverized coal power plant. However, these too suffer large EP s when compared to a standard IGCC plant running with no carbon capture (baseline 2). The EP for an IGCC with 80% capture is 17%, mainly due to the added energy intensive ASU and CO 2 separation towers. Oxy-coal combustion shows efficiencies below those of IGCC plants, which most likely is due to the energy intensive larger scale ASU s it requires. While the fact that carbon capture technologies can reach efficiencies equal to those of coal power plants already in use, the main roadblock is cost. Cost of Electricity Investing in an IGCC power plant requires being able to front a steep capital cost. They are a well proven technology that produces better returns in the long run than conventional pulverized coal power plants, but construction costs are much higher. This is due to a much more complicated design, as can be seen in Figure 3. A typical IGCC without carbon capture requires around $1 billion in investments to start up. This number only increases when adding on CC technology: an additional $166 million for 80% capture and $141 million for 60% capture. iv Current projections show the capital cost for oxy-fuel combustion plants with carbon capture to be lower than that of IGCC plants. Graph 2 shows the increase in cost of electricity (COE) for cases 1-6 when compared to the COE for a conventional coal plant with no capture (baseline 1). The COE takes into account both capital and running costs. Again, MEA projects as the most expensive, while IGCC with CO 2 capture achieves the best results. Page 13

15 % increase in COE Graph 2: % increase in Cost of Electricity MEA 90% SC-oxyfuel USC-oxyfuel IGCC 80% Capt IGCC 60% Capt IGCC 80% co-capture Cost of electricity is probably the most important parameter for potential coal power plant private investors because the COE is the greatest burden to making a coal power plant profitable. The profitability of a coal power plant lies in the ability to sell electricity at a competitive price, so the large percent increases in COE as can be observed from Graph 2 (all above 30% except for IGCC Co-capture) do not bode particularly well for its implementation at the private level in the near future. Some of these costs can be mitigated through governmental sponsorship; however, if the economy moves towards being greener as has been predicted for around 2020, power plants will eventually be competing evenly with carbon capture technology implemented across the entire energy sector. ii Environmental Impact: Mitigation Cost (MC) is the best parameter to compare the environmental impact of different power plants with carbon capture while keeping cost in mind. MC is defined by: iv Page 14

16 ($/tonne CO2 avoided) In the previous equation, E stands for CO 2 capture (tonne CO 2 /kwh) and the subscripts ref and cap stand for the reference and capture plants respectively. For reference, baseline 1 (conventional coal power plant) is generally used. The units of MC are therefore $/tonne CO 2 captured. This shows the direct cost in order to stop CO 2 from being emitted. Graph 3 shows the MC for cases 1-7. Oxy-coal and IGCC capture plants (cases 2-5) all have relatively similar MC s, with IGCC 80% capture the lowest for these 4 cases Cost for avoided CO2 Special Cases Case 6, IGCC with Co-capture, appears to be the clear-cut winner for overall feasibility when looking at Graphs 2 and 3. Cost is extremely low compared to all other cases, and in fact only a 7.6% increase in COE is observed if co-capture is instead compared to an IGCC plant without CO 2 capture (baseline 2). The reason for this small increase in electricity cost is due to lowered capital costs. The lowered capital costs result from a much simplified absorption process requiring one large absorption tower for both H 2 S and CO 2 instead of two separate ones, as well as an inherent increase in the flue gas stream pressure for this design that increases absorption efficiencies. However, the main flaw of this Page 15

17 system is not covered directly in the metrics of the comparisons used for this report: nobody has really thought of a use yet for a toxic acid gas composed of H 2 S and CO 2, the product of Co-capture. For normal CC processes, because the collected CO 2 is pure, it can be used for a variety of purposes. Many commercial processes require concentrated CO 2 (such as soda production or greenhouses), so it does have some marketability. Beyond that, it has been proven to a good extent to be safe when sequestered underground. Sulfur dioxide, on the other hand, has much more adverse effects when released into the environment including being a precursor to sulfuric acid (which causes acid rain) and particulate matter (which correlate to adverse climate change effects). xii If captured separately from CO 2, it too can be re-used industrially by being converted back into usable sulfur products, but concentrated with CO 2 it has little value. Also, because of the strong environmental awareness and lack of understanding of how H 2 S would store underground, sequestering a product stream from a Cocapture plant is currently not a legitimate option. Case 7 involves the possibility of a membrane system for absorption of CO 2 using a specific amino acid salt solution (CORAL ). The calculated MC comes from a cost estimate analysis done by the TNO, the company who owns (and is therefore promoting) CORAL solvents. xix Very large assumptions are made for this process for a full scale coal power plant, as only bench scale simulations have been performed. The energy consumption levels are almost solely based on the higher loading capacities of CORAL versus MEA (92 kg/m 3 and 55 kg/m 3 respectively), while many other chemical and absorption design factors affect the MC. The main point to take away from the research done by the TNO is that CORAL solvents do show good potential to be more efficient than MEA for post-combustion capture, however exactly how much more efficient has yet to be concretely determined. Their comparison to newer technologies like gasification and oxy-coal combustion is sketchy at best. Page 16

18 Retro-Fitting One other factor for the overall feasibility of large scale implementation of CC technology is how it can be applied to pre-existing coal power plants, or retro-fitting. MEA absorption requires the addition of spacious absorption and stripper towers onto a coal power plant s facilities, and the addition lowers the plant s energy efficiency by a large amount. Oxy-coal combustion has been shown to be a viable retro-fit because all the additions to a standard pulverized coal power plant can be done upstream and downstream of the combustion chamber, including adding an ASU and flue gas recycler. Gasification is a process that is harder to integrate into a previously designed combustion coal power plant due to the fact that it requires an entirely new chamber for gasification instead of combustion, as well as an added steam turbine in order to be efficient. While it is true that in order to achieve any sort of substantial reduction in global CO 2 emissions from coal power plants pre-existing plants would have to be dealt with, CO 2 capture really only makes sense for newer high efficiency plants. This is due to the EP as discussed earlier. In order to capture the same amount of CO 2, higher efficiency power plants require less energy. i This is seen when comparing the EP for MEA absorption (23%), the standard to for retro-fits, to that of IGCC with 80% capture (17%), a retro-fit for a newer more efficient IGCC power plant. Some literature suggests that because many of the coal power plants in the United States are expected to reach the end of their lifespan around 2020, during the same time that IGCC with CO 2 capture and oxy-coal combustion become more economically feasible, older plants could just be phased out for more energy efficient designs with CC. Conclusion Coal power is such a vital part to the economy of the United States, where over half the energy produced comes from coal-fired power plants, that phasing out its use quickly is simply unfeasible. Bridging the gap to the next generation of re-usable clean energy technologies requires tackling the Page 17

19 pollution problem of today. Coal power plants can be made cleaner burning by using different forms of CCS to keep CO 2 emission levels low. Subterranean sequestration is still under much research for long term effects, but is generally viewed by the scientific world as a safe form of CO 2 storage. Several different CC technologies offer potential for installation on large scale coal power plants. MEA absorption is the most industrially understood, but has well-observed low energy efficiencies due to the inherent solvent heating and cooling regeneration cycle. While it does achieve the ultimate goal of capturing around 90% of the CO 2 in the flue gas of a coal power plant, the costs associated with it, including both COE and MC, are much too high when compared to the newer technological alternatives. Oxy-coal combustion still has room for improvement in design due to the sizeable energy losses comes from the required large ASU. ASU technology has been a focal point over the last ten or so years and will continue to be in the near future in order to make both Oxy-coal combustion and coal gasification more efficient processes. The current standard method for air separation is cryogenic separation (cooling the air to a low enough temperature to condense out the oxygen). Since 2000, a 20% decrease in power consumption by this method has been achieved, and another 10% reduction is expected by v Because of this, along with the fact that Oxy-coal combustion has only been tested at small scales, the potential for future improvement of any of the three main technologies discussed is probably greatest for Oxy-coal. That being said, when comparing the three main variables discussed in this paper, the most favorable choice looks to be coal gasification with carbon capture. IGCC plants are an efficient design for coal power, so they offer a good starting point for carbon capture systems to be added onto. Case 4 (IGCC with 80% capture), offers the best overall results. It has the lowest MC of any case (outside of 6 and 7), and has an EP very close to that of IGCC with 60% capture and Co-capture. The main knock on this design therefore is the COE, which is 40% above the current standard. When compared to the other carbon capture technologies in question, it still has a fairly low COE, but in order to make this kind of Page 18

20 power plant with carbon capture economically competitive, major shifts in the economy towards greener thinking will have to happen. Ultimately, higher incentives will have to be made to energy producing corporations in order for carbon capture to catch on. As of today, no full scale coal power plant uses carbon capture because the costs associated with are too much of a hindrance. However, green design is an increasing factor of importance for newer coal power plants, and CCS does hold serious promise in reducing GHG emissions. While this report has demonstrated that there are some fairly efficient and promising methods of carbon capture, improvements will continue to be heavily researched and developed due to the large environmental and economic potential they offer. Page 19

21 References i. Gielen, Dolf, and Jacek Podkanski. Prospects for CO2 Capture and Storage. Paris: International Energy Agency, Print. ii. Farzan, H., S. Vecci, D. McDonald, and K. McCauley. "State of the Art of Oxy-Coal Combustion Technology for CO2 Control from Coal-Fired Boilers." Babcock and Wilcox, 17 May Web. 17 Dec < iii. "Oxy-Coal Combustion Overview." Babcock and Wilcox, Mar Web. 17 Dec < iv. Ordorica-Garcia, Guillermo, Peter Douglas, Eric Croiset, and Ligang Zheng. "Technoeconomic Evaluation of IGCC Power Plants for CO2 Avoidance." Energy Conversion and Management 47 (2006): Print. v. Tranier, Jean-Pierre. "Air Separation Unit for Oxy-Coal Combustion Systems." Air Liquide, 9 Sept Web. 17 Dec vi. vii. Powell, Julian. "Coal Gasification." Zentech. Zentech. Web. 17 Dec < Stoichevski, William. "Norway: Carbon Tax Permitting Oil-industry Growth (Scandinavian Oil-Gas Magazine)." Scandinavian Oil-Gas Magazine. Scandoil.com, 26 July Web. 17 Dec viii. Torp, Tore A. "Sleipner Project." IEAGHG - CO2 Capture & Storage. IEAGHG. Web. 17 Dec < ix. McFarland, Jim, Howard Herzog, John Reilly, and Henry Jacoby. "Economic Modeling of Carbon Capture and Sequestration Technologies." DOE. Web. 17 Dec x. Rozelle, Pete, and Jenny Tennant. "DOE - Fossil Energy: DOE's Coal Gasification R&D Program."Fossil Energy: Office of Fossil Energy Home Page. DOE, 28 June Web. 17 Dec xi. Tomanosky, Robert R., Patricia A. Rawis, Robert M. Purgert, and Vis R. Viswanathan. "Steam Turbine Materials for Ultra Supercritical Coal Power Plants." Project Facts: Advanced Research. DOE. Web. 17 Dec xii. "Sulfur Dioxide." US Environmental Protection Agency. EPA. Web. 17 Dec < xiii. Khosla, Vinod. "Long Shots." Foreign Policy - the Global Magazine of Economics, Politics, and Ideas. Foreign Policy, 10 Dec Web. 17 Dec xiv. Stephen A. Rackley. Carbon Capture and Storage. Oxford 2010: Butterworth-Heinemann. xv. xvi. xvii. Graeme Puxty, Robert Rowland, Andrew Allport, Qi Yang, Mark Bown, Robert Burns Marcel Maeder, and Moetaz Attalla. Carbon dioxide postcombustion capture: a novel screening study of the carbon dioxide absorption performance of 76 amines. Environ. Sci. Technol, 2009, 43, Anad B. Bao and Edward S Rubin. A Technical, Economic, and Environmental Assessment of Amine-Based CO 2 Capture Technology for Power Plant Greenhouse Gas Control. Environ. Sci. Technol, 2002, 36, Muñoz et al. New Absorbents for the removal of CO2 from gas mixtures. xviii. Goetheer, Earl. "First pilot results from TNO s solvent development workflow." Carbon Capture Journal. 1.8 (2009): 2-3. Print. xix. xx. xxi. xxii. Feron and Asbroek. New Solvents Based on Amino-Acid Salts for CO2 Capture from Flue Gases. Lenny Bernstein, P. B. (2007). Climate Change 2007: Systhesis Report. Valencia, Spain: IPPC. U.S. Energy Information Administration. (2009). Emissions of Greenhouse Gases in the United States Washington D.C.: U.S. Department of Energy. A.F. Portugal, J.M. Sousa, F.D. Magalhães and A. Mendes. Solubility of Carbon Dioxide in Aqueous Solutions of Amino Acid Salts. xxiii. Anne Minard. Carbon Sequestration Options. 17 Dec xxiv. IGCC Process Diagram. Page 20