Executive Summary
Background
Fossil fuel-fired power plants are among the biggest stationary sources of anthropogenic carbon dioxide (CO2) emissions. Excess levels of CO2 in the atmosphere could contribute to an increase in the average global temperature and lead to unfavorable climatic changes (Steinberg, 1984). Research in the area of CO2 recovery (prior to its storage or utilization) from large power plants is considered the first step in tackling the ever-growing CO2 problem.
The amount of CO2 generated from a power plant depends on the fuel conversion technology employed in the power generation process. Generally, incorporating CO2 capture technologies into power plants introduces energy penalties. This project addresses the integration of CO2 capture in a 500 MWe power plant without incurring major efficiency losses.
Methodology
Various CO2 capture methods and power generation technologies were examined with respect to net power generation efficiency, amount of CO2 captured, and scale-up considerations. The capture methods investigated include membrane technologies for both pre- and post-combustion separation of CO2 and adsorption/absorption technologies. Advanced power generation technologies evaluated were oxy-combustion, chemical-looping combustion (CLC), natural gas reforming combined cycle (NGRCC), and integrated gasification combined cycle (IGCC). Conventional means of power generation without CO2 capture (e.g., air-fired pulverized coal combustion and fluidized bed combustion) formed base cases to evaluate advanced combustion technologies with CO2 capture. IGCC and CLC emerged as efficient options for future coal- based power plants, but only IGCC fit the design objective of achieving 500 MWe generation.
Cases Considered
Coal-based IGCC
Bituminous coal was chosen as the feedstock for the IGCC system (Table 2-2). An oxygen- blown, E-gas gasifier produced the syngas (composition after cleanup: 0.468 mol CO, 0.333 mol H2 and 0.148 mol CO2). A water-gas-shift reactor converted the syngas to a concentrated stream of H2 and CO2. A palladium-based membrane system was used to separate the H2 that was then sent to the gas turbines. The required gross power output is ~799 MWe at a 35.4% thermal-to- electric efficiency (HHV-based) (Table 2-3). All CO2 produced (~10.733 106 kg CO2/day) is captured. This current design introduces a 14% energy penalty for the CO2 capture compared to IGCC without capture. The exit gas composition of the current system is 68.3% CO2, 12.5% CO, 12.5% H2O, 6.8% N2 and others.
Coal-based CLC
CLC was investigated as a supplementary power generation source (~150 MWe) using some syngas produced from the gasification unit. The chosen CLC system comprises interconnected fluidized bed reactors with a steam cycle for power generation. A nickel-based oxygen carrier with NiAl2O4 as the binder was chosen as the bed material for the reactors. CLC is considered as a conceptual clean combustion technology.
Technical Conclusions and Recommendations
The efficiency of power generation of the proposed IGCC system with palladium membranes is approximately 35.4%. Integration of CLC with IGCC can slightly improve system efficiency by approximately 0.3%.
It is also noted that there is a considerable amount of recoverable energy in the form of CO in the exit gas, which needs to be addressed. The current design considering 100% CO2 capture can also be modified to improve electricity generation efficiency.
Chapter 1: Introduction
The world’s consumption of energy has increased rapidly in the past century, with a large portion of the usage coming from the combustion of carbon-based fossil fuels such as coal, petroleum and natural gas. Carbon dioxide (CO2) is a greenhouse gas typically formed via the combustion of fossil fuels. In 2002, it was estimated that over 82% of the United States’ anthropogenic greenhouse gas emissions can be attributed to the CO2 released from fossil fuel-based power plants (EIA report, 2002). Excess levels of CO2 in the atmosphere could lead to an increase in the average global temperature and lead to adverse climatic changes (Steinberg, 1984). World CO2 emissions are expected to double by the year 2030 if no specific policy initiatives and/or measures are taken (WETO, 2003).
The capture and sequestration, or secure storage, of CO2 released from power plants and steel/cement factories can be perceived as a long term strategy towards significant reduction in CO2 emissions (Herzog 1999, 2001). The project goal was to design a feasible technological solution for mitigating CO2 emissions from a stationary fossil-fuel based power plant while reducing trade-offs in energy efficiency. Several methods of CO2 capture were investigated toward achieving maximum CO2 emission reduction from electric power plants of 500 MWe scale without significant losses in electricity generation efficiency (η). The percentage of CO2 emission avoided from the total plant emission was defined as CO2 capture effectiveness (θ). Figure 1-1 demonstrates the project goal graphically. It shows η vs. θ for existing power plants and the projections for future power plants with CO2 capture.
Figure 1-1 Schematic of η vs θ for existing and future power plants
Existing power plants with post-combustion CO2 capture tend to have low efficiency (lower- right of Figure 1-1) whereas future power plants with CO2 capture are projected to have higher efficiencies (upper-right corner).
1.1 Evaluation of CO2 Capture Options
The following CO2 capture schemes were investigated as possible components to a 500 MWe- scale power plant: 1) membranes; 2) solid adsorption; 3) solvent absorption; and 4) biomass utilization. Brief descriptions of these technologies are presented within this section.
1.1.1 Membranes
Membranes have become an established technology for CO2 removal since a polymeric membrane was first used in this application in 1981 (Dortmundt and Doshi, 1999). Polymeric membranes are have been used for CO2/CH4 and CO2/N2 applications. However, they have the following limitations: 1) low selectivity; 2) lack of high-temperature stability (Bredesen et al., 2004); and 3) plasticization of polymer membranes with high CO2 partial pressures leading to decreased separation ability (Li et al., 2004). These limitations make integration of polymeric membranes into power plants challenging.
Microporous inorganic membranes with pore sizes between 0.2 and 0.8 nm have been studied for gas separation due to their superior thermal, mechanical and chemical stabilities, good erosion resistance, and high pressure stability compared to conventional polymeric membranes (Li et al., 2004). They can be used to separate CO2 from CO2/CH4, CO2/N2 and CO2/H2 mixtures according to different pore sizes.
Palladium-based (Pd-based) membranes can be used only for CO2/H2 separation and have perfect performance with little energy consumption (Roa et al., 2003). Cost (Tennison, 2000) and stability (Bredesen et al., 2004) for this kind of membranes are the main limitations when used in industry.
Further details about membranes are provided in Appendices A and B.
1.1.2 Solid Adsorption
Adsorption separation technologies can operate over a large range of temperatures and pressures. Several different materials were reviewed including activated carbons, hydrotalcite-like materials, molecular baskets and other adsorbents. The high selectivity and wide operating range make it a potential and competitive alternative for CO2 capture. However, since the technology is nascent and requires detailed studies it was not employed in the project. More information can be found in Appendix C.
1.1.3 Solvent Absorption
Solvent absorption technology is based on the chemisorption of the CO2 onto an amine-based solvent, which reacts with the CO2 to form unstable carbamates. These carbamates are decomposed back into the solvent and CO2 by heating with low pressure steam. The regenerated solvent is then routed back to the absorption chamber (Yeh and Bai, 1999). The most commonly used solvents today are usually primary, secondary or tertiary amine-based. Some of these solvents have a corrosion inhibitor added to them for longer corrosion resistance. This is the only post-combustion process that has been commercially developed for a scale of 500 MWe power
plants, which is its main attractive feature. This process is mainly suitable for flue gas streams with low CO2 concentrations. Therefore, it is incompatible with inherent combustion techniques (e.g., oxy-combustion and chemical-looping combustion) that produce concentrated CO2 streams. Another major disadvantage of this process is that it is very energy intensive as the flue gas has to be cooled down to 40°C before being sent to the absorber because the solvent degrades above 50°C. Again the stripping part is to be conducted at a temperature of 105°C which needs a high energy requirement.
Solvent absorption may be used as an alternative technology for CO2 capture in place of the proposed capture design methodology for CO2 with some tradeoffs for energy consumption. Since absorption is a commercialized technology, the availability of the solvents is abundant. Thus with future design modifications of using membrane contactors in place of the traditional contactors , this process may emerge as one of the most feasible post combustion technologies for CO2 capture. Appendix D contains further information on solvent absorption.
1.1.4 Biomass Utilization
Biomass usage for electricity generation and process heat has a good potential to come up again mainly because of the fact a lot of biomass comes from agricultural and municipal wastes in today’s world (Audus and Freund, 2004). Furthermore, biomass offers a passive route to CO2 capture because trees and plants are natural CO2 removers of the environment over short periods of time. The key issue for biomass utilization for providing energy needs with simultaneous CO2 mitigation strategy depends on two factors: 1) a feasible method of collection of unwanted solid and liquid organic wastes and delivery to a processing or combustion site; and 2) the sustainable growth of energy crops in a manner such as to provide net energy (i.e., energy obtained from the crops should exceed overall energy in planting and growing the crops.). When these two broad issues are addressed successfully, biomass can be used to provide a net reduction in overall CO2 emissions from power plants and other energy delivery locations.
It was decided not to pursue biomass usage options further mainly because of the diverse supply stream of biomass which makes it hard to characterize it as one fuel into a narrow calorific value range. However, if biomass usage were to be considered as a serious option for power generation, then further research on co-firing options and gasification processes would perhaps yield the best results towards electricity generation. More details can be found in Appendix E.
1.2 Evaluation of Advanced Power Generation Methods
The following advanced power generation methods were investigated as possible suppliers of 500 MWe: 1) oxy-combusion; 2) chemical-looping combustion; 3) natural gas reforming combined cycle; and 4) integrated gasification combined cycle. Brief descriptions of these technologies are presented within this section.
1.2.1 Oxy-Combustion
The combustion of fuels in pure oxygen holds the promise of inherently providing a concentrated and capture-ready stream of CO2 which substantially reduces separation costs (Singh et al., 2003). This is because there is no dilution of the combustion air and hence the flue gas volume is substantially reduced. CO2 concentrations in the flue gas are also higher than 80% by volume compared to air-based combustion with flue gas CO2 concentrations in the range of 12-15%.
From a detailed investigation of available literature, there appears to be a substantial promise in oxy-fuel combustion as a near term to medium term CO2 capture strategy especially if development of advanced oxygen transport membranes achieves success (Acharya et al., 2005). However, currently the cost of air separation using cryogenic procedures puts oxy-combustion at a slight disadvantage compared to other technologies such as IGCC when it comes to the issue of CO2 capture with power generation. Because of this reason, oxy-combustion was not incorporated in the design. More information about oxy-combustion is contained in Appendix F.
1.2.2 Chemical-Looping Combustion
Chemical-looping combustion (CLC) is based on the principles of oxy-combustion and can inherently separate CO2 while burning the fuel necessary to generate power. Oxygen is needed for combustion and is provided by regenerable solid metal oxides that are circulated between two separate reactors: a fuel reactor and an air reactor (Ishida and Jin, 1994). Reduction of the metal oxide particle occurs in the fuel reactor allowing the oxygen from the metal oxide to react with the fuel. The reaction between the oxygen and the fuel produces high temperature and high velocity gases, which can then be passed through a turbine for power generation or heating process material (Anheden and Svedberg, 1998; Ishida and Jin, 1994; Ishida and Jin, 1997). Next the reduced metal oxide particle is routed, or looped, to the air reactor where oxidation of the reduced metal particle occurs from an incoming stream of air. The oxidized metal particle is then looped back to the fuel reactor where it again reacts with the fuel to repeat the aforementioned cycle of reduction and oxidation. Figure 1-2 demonstrates the basic concepts of CLC.
Figure 1-2 Simplified schematic of the CLC process (Lyngfelt et al., 2001)
CLC is presently limited by a lack of industrial-scale research including advanced development in the metal oxide particles needed to carry oxygen from the air reactor to the fuel reactor. However, CLC can potentially capture over 90% of CO2 produced within the fuel reactor without decreasing the efficiency of the overall looping process. CLC also offers fuel flexibility as both gaseous and solid fuels can conceptually be used (Griffin, 2003). CLC shows promise as an imminent efficient power generation technology while capturing CO2, and thus is chosen to be incorporated into the overall design (further discussed in Chapter 3).
1.2.3 Natural Gas Reforming Combined Cycle
Natural gas reforming combined cycle is the integrated power plant of hydrogen production and hydrogen combustion turbine cycle. The carbon is removed from natural gas prior to hydrogen combustion so that no CO2 is discharged during combustion. It is one of the cleanest and efficient technologies for electric generation and CO2 capture.
However, from the comparison of various power plant technologies with CO2 capture, the efficiency of natural gas reforming combined cycle is not as high as natural gas combined cycle and the total capital cost is around 40% higher than that of NGCC. Moreover, the natural gas price is expected to increase steadily until the year 2030. Since natural gas is not cost- competitive, the cost of electricity of steam reforming combined cycle is higher than those of other coal power plant. Appendix G has further information about natural gas reforming with combined cycle and also on the abovementioned comparisons.
1.2.4 Integrated Gasification Combined Cycle (IGCC)
IGCC combines gasification technology with combined cycle technology. The first step in the IGCC process is gasification. Gasification converts any hydrocarbon into a synthesis gas comprised mainly of hydrogen (H2) and carbon monoxide (CO) at high temperature and pressure. The gasification process allows the separation of the pollutants from the synthetic gas. With CO2 capture option, syngas passes through a Water Gas Shifter (WGS) and converts the syngas to primarily CO2 and H2. Next the syngas is “cleaned-up” by removing the acid gases (such as hydrogen sulfide), particulate matter, Hg and other pollutants. After the CO2 separation unit, CO2 can be stored and hydrogen is combusted in a combined cycle gas turbine that produces electricity. Both the syngas production process and the gas turbine combustion processes generate steam that is utilized to produce electricity.
Advantages of IGCC include the reduction of CO2 emissions, increased efficiency, and flexible fuel supply. IGCC technology with CO2 capture also results in superior environmental performance by reducing emission of pollutants (e.g., SO2, NOx, particulate matter, and mercury). The collection of sulfur and gasification slag obtained from the process has byproduct value, which avoids the cost of byproduct disposal, and easier CO2 removal. The energy consumption for CO2 capture is lowest in comparison with conventional power plant and NGCC plant.
The main disadvantage of IGCC is the capital cost. In addition, IGCC is a complex process that requires a high degree of component integration.
1.3 Design Methodology
Based on the literature survey, both the methods of CO2 capture and the technology of energy conversion were found to influence the overall plant efficiency and the amount of CO2 that can be captured. The problem was to design a 500 MWe power plant that incorporated a CO2 capture system. Available systems exist at a wide range of scales from small-scale gas turbines (~5 MW) to large-scale commercial PC units (1000 MW). Several technologies were evaluated on a thermodynamic basis to find mass and energy inputs and outputs involved in the respective method. Next the kinetic limitations to scaling-up from a given size to 500 MWe were determined. Based on some of these preliminary calculations, gasification-based processes (e.g., IGCC) and CLC emerged as efficient options for future coal-based power plants. These power generation technologies were integrated with selected CO2 capture technologies to recover a high percentage of the CO2 produced (> 90%) while maintaining reasonable power generation efficiency (> 30%). Figure 1-3 shows the comparative efficiencies of the power generation technologies considered.
Figure 1-3 Comparative efficiencies of various power generation technologies (Nsakala et al., 2003)
Chapter 2: Proposed Design
This chapter describes the proposed design for the capture of CO2 produced from a 500 MWe power plant. The various sections cover the choice of fuel, the fuel conversion technology and its components, the specific CO2 separation technology adopted, auxiliary power plant components, environmental concerns and CO2 handling issues.
2.1 Why Coal-Based IGCC?
According to the World Energy Technology and Climate Policy Outlook 2003, coal represents 25.5% of total global energy usage and generates 38.7% of global electricity. By 2030, global coal use is expected to have doubled from today’s consuming levels. Moreover, coal reserves are last longer than other resources such as oil and gas, with a confirmed global reserves-to- production ratio of over 230 years. Thus, coal is expected to generate 45% of global electricity. Many countries all over the world will be heavily dependent on coal for electricity production because of its abundance and world wide distribution (WETO, 2003). In addition, coal is regarded as the potential feedstock for future power plants because the price of natural gas is rising and unpredictable (refer to Figure G-2 in Appendix G).
Based on these considerations, coal is a good fuel feedstock for the team’s proposed power plant. The only problem to be considered is the inevitable emission of CO2. Assuming all the coal is completely oxidized during the process of electricity generation, a 500 MWe power plant with 40% thermal-to-electricity efficiency produces about 9.5 million kilograms of CO2 (David and Herzog, 2000). Technology is available to reduce CO2 emissions by employing a CO2 capture system to prevent most CO2 from being directly vented to the atmosphere. Pre-combustion decarbonization is a potential technology to remove CO2 before burning the fuel. However, the overall efficiency can decrease when a new device is added since additional energy is required to operate for the same efficiency, or in other word, the cost of electricity is comparably high.
Studies indicate that coal-based IGCC has the capability for combined reduction of CO2 emissions and increased efficiency compared to conventional power plants (David and Herzog, 2000). Cost model comparisons by David and Herzog (2000) for different technologies are shown in Table 2-1.
Table 2-1 Cost model for capture plants, in 2000 and 2012 (David and Herzog, 2000)
NGCC and PC power plants with CO2 capture incur the highest additional costs compared to IGCC. IGCC has the lowest extra energy requirements at the rate of 0.194 kWh/kg of CO2 avoided (David and Herzog, 2000). In addition to its relatively low energy consumption with CO2 capture, IGCC technology is also environmentally friendly by reducing SO2, NOx, mercury and particulate matter emissions (Bechtel, 2003).
2.2 Coal Selection
The rank of coal to be used as fuel plays a vital role in plant emissions. There is a tradeoff between lower CO2 emissions and greater overall efficiency. Increasing the unit’s efficiency is another way to reduce CO2 emission, because less coal is burned per unit electricity generated (Figure 2-1) (Booras, and Holt, 2004).
Figure 2-1 CO2 emission vs. Net plant efficiency (Booras, and Holt, 2004)
Table 2-2 CO2 emissions from fossil fuels with bituminous coal as the base case (Göttlicher, 2004)
Bituminous coal is widely used in gasification. In comparison with other types of coals, its heating value and relatively low CO2 production make it an appropriate choice as the feedstock for the IGCC process (Table 2-2) (Göttlicher, 2004).
2.3 IGCC Components
The costs of CO2 removal vary significantly between the various coal gasification technologies and is related to feedstock choice (i.e., different coals, biomass and coal co-gasification) (Booras, and Holt, 2004). The current procedure in IGCC technology is gasification of coal, biomass, or petroleum coke in a gasifier to produce raw synthesis gas (syngas), which is mainly composed of CO and H2. The raw syngas is then cleaned and sent to a water-gas shift reactor to convert the CO to CO2, which can be separated to produce high purity of CO2 and H2. In order to achieve the highest possible percentage of CO2 capture, the Pd-membrane will be used as the CO2 capture method. Figure 2-2 shows the scheme of proposed 500 MWe IGCC power plant.
Scheme of IGCC
Figure 2-2 Schematic diagram of the IGCC power plant (adapted from Bechtel, 2003)
The following sections introduce IGCC components separately.
2.3.1 Air Separation Unit
A key issue in gasification systems is whether the gasifying agent is oxygen or air (i.e., will an air-blown or oxygen-blown gasifier be employed). Oxygen-blown gasifier produces syngas with a higher calorific value, because it is not diluted by nitrogen in the air. Oxygen of 95% purity by volume can be supplied from cryogenic air separation units (ASU). Without the presence of nitrogen, the size of downstream components would be smaller in the design. The only drawback of oxygen-blown gasification currently is that the ASU is costly and a complex piece of equipment.
2.3.2 Gasifier
Several types of gasifiers are available on commercial scale. The available types are fixed-bed gasifiers (operated in counter-current, co-current or cross-current mode), fluidized bed gasifiers, and entrained flow gasifiers. These gasifiers have different hydrodynamics, which stem from the way in which the solid fuel and the gasification agent (e.g., air, oxygen and/or steam) are contacted and different operating conditions such as temperature and pressure (Bergman, 2004).
The fixed bed gasifier has long residence times, which imply a low throughput and hence have limited application in large scale IGCC plants (Simento, 2005). Fluidized bed gasifiers have a uniform temperature distribution. Their advantages include the high heat transfer rates of coal on entry and the gasifier can operate at variable load. However, the relatively low temperature operation limits the use of fluidized bed gasifiers to reactive and predominantly low rank coals. Entrained Flow Gasification is specifically designed for low reactivity coals and can handle high coal throughput. The advantage is the high reaction intensity because of high pressure (2-6 MPa) and high temperature (>1300°C) environment in the entrained flow gasifier. Single pass carbon conversions are in the range of 95-99% (Simento, 2005).
Entrained flow gasifiers can process all ranks of coal, but have disadvantages of increased cost and reduced performance when using low rank/high ash coals. For slurry-fed gasifiers (Texaco, E-Gas) the energy density of high moisture and/or high ash coal slurries is markedly reduced, which increases the oxygen consumption and reduces the gasification efficiency. For dry coal- fed gasifiers (Shell) there is an energy penalty (and therefore reduced steam turbine output). The high partial pressure of CO2 could allow for the use of more efficient capture technologies (i.e., physical absorption). The higher concentration of CO2 at a higher pressure means the volume of gas being treated is lower. This makes CO2 capture with IGCC more efficient and potentially reduces the costs (Eide and Bailey, 2005).
Due to these reasons, the gasifier employed is the E-Gas technology from Conoco Phillips. It is an oxygen-blown coal gasification technology featuring a slurry-fed, two-stage gasifier. The syngas produced is at 1038°C, contains entrained solids from the second stage and is cooled in a fire-tube boiler to produce saturated high-pressure steam (ConocoPhillips, 2006). Since the feed capacity of an E-Gas gasifier is 2,750 TPD, two gasifiers are needed for the current design (ConocoPhillips, 2006).
2.3.3 Gas Cleanup
Syngas has to be free of particulates, tars, sulfur, and alkali metals to prevent corrosion of the IGCC components (Bechtel, 2003). Particulate removal to protect the turbine blades from erosion requires filtration technology. Alkali metal removal (e.g., Na, K) is needed to avoid deposition and corrosion of the turbine blade materialse (Booras and Holt, 2004). Gas cleanup processes and components vary with different designs and deals with particulate, mercury, and acid gas removal (AGR).
For particulate removal, the syngas from gasification process is scrubbed and filtered using bag filters (EPA Report, 1998).
A coal gasifier may emit mercury in several different forms, primarily as elemental mercury (Hg0), mercuric chloride (HgCl2) and mercuric sulfide (HgS) (Alptekin et al., 2003). Depending upon the conditions, these compounds may exist as gaseous or in the form of micro-particles (i.e., aerosols) at concentrations in low ppb levels. Mercury removal can be achieved via activated carbon beds. The cost of more than 90% volatile mercury removal from a coal gasification-based plant would be only one-tenth of that from a pulverized coal combustion- based plant of comparable capacity (Klett et al., 2002). Because the gasifier operates under high pressure, the syngas stream is compressed to a volume that is approximately 1-2% that of the post-combustion flue gas from a similar-sized pulverized coal plant (Klett et al., 2002).
Conventional AGR systems are based on methyldiethanolamine solvent, which removes the main sulfur compound H2S in the gas. An acid gas stream is produced to a sulfur recovery unit. The sulfur recovery unit converts H2S to elemental sulfur, which is greater than 99.99% pure. The sulfur can be sold for agricultural applications (Grasa et al., 2004). However, the disadvantage of these absorption-based techniques for the purification of syngas is that hot syngas must be cooled to ambient temperature and then preheated to a high temperature before can be used for Palladium-based membrane.
The raw syngas exiting the syngas cooler is filtered to remove the unreacted entrained solids, which are recycled to the gasifier. The filtered “sour” gas consists mainly of hydrogen, carbon monoxide, carbon dioxide, water, and smaller quantities of nitrogen, methane, hydrogen sulfide, and carbonyl sulfide (COS) (Booras and Holt, 2004).
A better alternative is to treat the syngas in a hot gas cleanup device. It can avoid heat loss and save energy. Hot gas cleaning units (HGCUs) has been developed and appears to be the major technique for removal of hydrogen sulfide from hot raw syngas. The basic high temperature sulfidation reaction is shown as follows:
MO + H2S → MS + H2O (sulfidation) [2-1]
where MO and MS are the metal oxide and metal sulfide, respectively. The sulfide sorbent can be regenerated through reaction with diluted air (Ko et al., 2006). The main difference between hot gas cleaning units (HGCUs) and conventional acid gas removal technologies is that HGCUs operate at higher temperatures and pressures, which eliminates the need for gas cooling (Grasa et al., 2004).
2.3.4 Water-Gas-Shifter (CO conversion)
Water-gas-shift reaction (WGS) is an important reaction in hydrogen production from syngas from coal gasifier. This process is the step in which CO in the syngas to be converted into hydrogen and CO2 through WGS. The major difference between different schemes is the number of units and the temperature levels, high temperature (HT) shift at 350°C, medium temperature (MT) shift at 250-300°C, and low temperature (LT) shift at 190°C -210°C. The choice is between HT and LT, or a MT shift reactor. The larger amount of CO2 converted from CO is better because it guarantees high CO2 capture and reduces poisoning of the Pd-based membrane (Section 2.3.5). State-of-the-art WGS can have over 95% CO conversion at specific ratios of steam/CO and at specific temperature (Gottlicher, 2004). Figure 2-3 shows the syngas composition according to steam/CO ratio and temperature.
Figure 2-3 Syngas composition after WGS according to a) steam/CO ratio when T=300oC, and b) temperature when steam/CO=1
As the syngas has low hydrogen concentration (~33%) after gasification and gas cleanup processes, we tried to increase hydrogen concentration by using WGS. The reaction is exothermic, but the energy produced is not high enough to convert water to steam. If the steam amount is increased to steam/CO=2, H2 concentration will increase and CO will get lowered than that when steam/CO=1. However, higher steam ratios require higher energy consumption. Likewise, if WGS reactor is operated at low temperature, we can get high hydrogen concentration. However, the palladium membrane needs to operate around 300°C. With these reasons, we focused on MT shift reaction and steam/CO ratio is 1.
2.3.5 Palladium Membrane Hydrogen Purifier
Pd-based membrane, which follows the diffusion-splitting mechanism, is theoretically capable of completely separating hydrogen from other gas (Bredesen et al., 2004). Pd-based membrane hydrogen purifier operates via pressure driven diffusion across palladium membranes. Only hydrogen can diffuse through the palladium membrane, which is typically a metallic tube composed of palladium and silver alloy material. It has the unique property of allowing only monatomic hydrogen to pass through its crystal lattice when it is heated above nominally 300°C. The hydrogen molecule contacted with the palladium membrane surface dissociates into monatomic hydrogen and passes through the membrane. On the other surface, the monatomic hydrogen recombines to form molecular hydrogen. Compared to the capture technologies like pressure swing adsorption (PSA) system considered by Eide and Bailey (2005), this technology has higher potential to separate CO2/H2. Further details of this technology can be seen in Appendix Section A.3.
2.3.6 Heat Exchanger
The reject gas coming out from the Pd-based membrane is cooled to 100°C in a heat exchanger with water as a coolant. The steam produced in this case is recycled back to the WGS reactor which meets 25% of the steam requirements for the reaction. This calculation can be found in Appendix Section H.5.
2.3.7 Flue Gas Treatment
Possible ways of obtaining pure CO2 with less energy penalties were considered. The reject gas coming out of the Pd membrane has the composition: 68.3% CO2, 12.5% CO, 12.5% H2O, and 6.7% N2 (mole basis). Simple membrane systems were evaluated as an option to obtain pure CO2 streams. However, based on certain calculations of energy penalty and mass balance, this proved unsuitable. Further information on the types of membranes considered for this can be seen in Appendix B, with the specific explanation of calculations regarding gas treatment seen in Appendix Section B.2.
2.3.8 Power Generation Unit
The power generation unit is composed of gas turbine generator (GTG), steam turbine generator (STG) and heat recovery steam generator (HRSG) (Figure 2-4). Combustion exhaust gases are routed from the GTGs to the HRSGs and stacks.
Figure 2-4 Schematic of Power Generation Unit (Kramlich, 2005)
A hydrogen combustion turbine can be powered by steam generated from the internal combustion of hydrogen as a fuel mixed with pure oxygen. As it is possible to use a closed cycle system, it benefits in cycle efficiency and reduction of environmental pollution comparing with other fuel gas turbine (Sugisita, 1998; Gambini, 2005). The HRSG receives the gas turbine exhaust gases and generate steam at the main steam and reheat steam energy levels. It generates high pressure steam and provides condensate heating for both the combined cycle and the gasification facilities. Heat transfer surface is of the extended surface type, with a serrated fin design.
The main problem with combusting hydrogen in current turbines is that it will result in increased NOx emissions due to an increased flame temperature. Applying hydrogen at a fuel to a conventional air breathing gas turbine cycle would not generate CO2, but NOx would be generated because N2 is present in the air (Sugisita, 1998). In the current gas turbine technology, fuel dilution with nitrogen is the most feasible option. However, the dilution with nitrogen cannot reduce NOx emission amount, but moderately decreases the concentration of it.
Another way to reduce NOx emission is to apply high oxygen concentration to gas turbine using ASU unit. Figure 2-5 shows the comparison of NOx emission after gas turbine. When 95% oxygen is introduced from air separation unit, the NOx emission from gas turbine can be reduced by 80%. However, using an ASU decreases total energy efficiency of power plant (Sugisita, 1998).
Figure 2-5 NOx emission after gas turbine according to use of air separation unit
2.3.7 Calculation Results
The purpose of doing some calculations based on assumptions is to have some general ideas about the energy penalty when using different CO2 capture technology combined with IGCC system. The details of the calculations and the related assumptions are shown in Appendix H. Table 2-3 shows the condensed results.
Table 2-3 Calculation results of IGCC system combined with different CO2 capture technology
From Table 2-3, we can see that the IGCC systems with less amount of CO2 emission has higher energy penalty and is less efficiency. Although the consumption of coal in pre-combustion system is higher and the efficiency of the system is lower than post-combustion system, the efficiency drop when using Pd-based membranes can be justified if near zero CO2 emissions are sought. Therefore, our IGCC design is going to use Pd-based membrane after WGS as the pre- combustion CO2 capture technology, due to its high selectivity and potential for the future.
2.3.8 Environmental Benefit
IGCC is the cleanest solid fuel technology (see Table 2-4). Unlike the direct combustion process in conventional PC power plants, pollution prevention in IGCC is achieved through removal of source pollutants before combustion. The gas cleaning process in IGCC lowers the emission of acid gases (i.e., SOx, NOx) and trace metals (i.e., Hg). Air emissions from an IGCC power plant are far below current U.S. Clean Air Act standards (Herzog, 2001). Specifically, sulfur removal efficiencies of more than 99% are achievable (Booras and Holt, 2004). IGCC systems are able to achieve exceptional levels of environmental performance, availability, and efficiency.
Table 2-4 Environmental Benefit of IGCC, Pollutants Emission Comparison
From the calculation result, we can see that our modified IGCC system with less amount of CO2 emission has higher energy penalty and is less efficient. This system can be further optimized to improve the power generation efficiency if trade offs in CO2 capture percentage are considered.
Chapter 3: Implementing CLC
As previously mentioned, CLC is presently limited by a lack of industrial-scale research (Lyngfelt and Thunman, 2005; Johansson et al., 2006). Metal oxide particle development has also not reached advanced stages as research in this specific area is ongoing. Therefore, allowing CLC to account for a smaller portion (~150 MWe) of the overall power required for a 500 MWe scale power plant is being considered. Specifically, a fraction of the auxiliary power required to run the IGCC system described above (~211 MWe) can potentially be supplied by CLC.
In this chapter, a brief overview of the fundamental concepts surrounding CLC is presented followed by a discussion of the fuel, looping material, and reactor design chosen for CLC to potentially complement the aforementioned IGCC and gas handling processes.
3.1 Fundamental Concept of CLC
The fundamental chemical reactions occurring within the two reactors of a CLC system are as follows (Ishida and Jin, 1997):
3.2 Selection of Fuel
The chemical composition of the fuel ultimately contributes to the formation of CO2 based on the theorized reactions occurring within the fuel and air reactors seen in Reactions [3-1] and [3-2], respectively. Gaseous fuels (e.g., CH4, coal-based syngas, biomass-based syngas, and H2) are generally preferred in CLC since solid fuels will likely inadvertently loop, or travel, with the metal oxide particle from the fuel reactor to the air reactor where it will be burned up (Lyngfelt et al., 2001). However, research involving the indirect gasification of solid fuels (e.g., coal, biomass) within CLC designs has recently been proposed (Griffin, 2003) and may be viable in the near future.
Coal-based syngas produced from the IGCC unit previously described in Chapter 2 will be utilized in the CLC design described herein. This decision is two-fold: 1) ease of implementation based on availability and cost of coal, and 2) aid in future research. Firstly, the abundance and cheap cost of coal is favorable compared to CH4 and H2 (Naturalgas.org, 2004; NAE and BEES, 2004), and the convenience of the coal-based syngas being producing from the IGCC process eases integration in the proposed CLC system. Secondly, the integration of this CLC system with the IGCC and gas handling systems proposed above can serve as a small-scale demonstration unit that can augment current and future research into the large-scale implementation of CLC using coal-based syngas. The syngas used for the proposed design integration is thus comprised of ~ 47 wt.% CO, ~33 wt.% H2, ~15 wt.% CO2, and ~5 wt.% inert gases (e.g., Ar, N2) with a calculated HHV of 11,295 kJ/kg (or 285 BTU/scf) (Bechtel, 2003).
3.3 Selection of Looping Material
Choosing a metal oxide that can thermally withstand multiple reduction-oxidation cycles necessary for CLC is a major technical issue. The most studied looping materials in the literature are Ni-, Mn-, Cu- and Fe-based. Particles instead of powdered forms, are preferred for CLC because powdered forms can introduce dust into the reactors, which may disrupt the reactions (Ishida and Jin, 1997). Particle forms also show enhanced reactivities and regenerability when used in such a cyclical process as CLC (Ishida and Jin, 1996). Furthermore, pure metal oxides can be damaged (e.g., develop cracks on their surfaces, shrinkage of particles) or have poor reactivity (e.g., low reduction-oxidation conversion) (Ishida and Jin, 1996). Therefore, inert “binders” are mixed with the pure metal oxides to combat the poor reactivity and mechanical qualities often associated with pure metal oxides. The most studied binders include yttria-stabilized zirconia (YSZ), NiAl2O4, ZrO2, TiO2, and SiO2. The binder does not participate in any reactions but can increase the reaction rate and particle durability of metal oxides within the two reactors at elevated temperatures (Ishida and Jin, 1994).
From the available literature on the reaction of coal-based syngas with various metal oxide particles (Garcia-Labiano et al., 2006; Jin and Ishida, 2004; Mattisson et al., 2006), NiO mixed with the NiAl2O4 binder (NiO/NiAl2O4) has emerged as a favorable looping material for this CLC system. The particles were prepared via freeze granulation method (Garcia-Labiano et al., 2006) according to a similar study by Cho et al. (2005). This process generally involves spraying a slurry of the metal oxide and binder mixture (i.e., NiO powder, aluminum oxide powder, distilled water, and a dispersion agent called Duramas D-3021) into liquid nitrogen to form frozen spherical particles (Cho et al., 2005). Water is removed via freeze-drying and then the particles are pyrolyzed to remove organic material and were sintered at 1300°C for 4 hours. The NiO metal oxide forms metal aluminate compounds (e.g., NiAl2O4) via reaction with the Al2O3. Physical and chemical properties of the particular NiO/NiAl2O4 particle considered for this study can be seen in Table 3-1.
Table 3-1 Properties of the NiO/NiAl2O4 looping material as prepared by Garcia-Labiano et al. (2006)
From Table 3-1, the oxygen transport capacity is the theoretical maximum amount of the metal oxide that can be used in oxygen transfer (Mattisson et al., 2006) and is dependent on the percentage of active metal oxide in the looping material (Garcia-Labiano et al., 2006). The oxygen transport capacity of NiO/NiOAl2O4 can be calculated from the following equation
Crushing strengths are important in determining whether the structural or mechanical integrity of the looping material has decreased prior to input in a CLC process. The crushing strength associated with this specific particle was not determined by Garcia-Labiano et al. (2006) and cannot be inferred from the study by Cho et al. (2005). However, Mattisson et al. (2006) did study how crushing strengths of 0.180-0.250 mm sized NiO/NiAl2O4 particles (with 40% active NiO content) can be affected by the sintering temperatures during preparation. These results are summarized in Table 3-2. This table shows that there is no general trend regarding crushing strengths associated with increasing sintering temperatures for this particular metal oxide particle.
Table 3-2 Variation in crushing strengths of NiO/NiAl2O4 looping material (Mattisson et al., 2006)
The associated thermodynamic and kinetic reactivities of this looping material will now be presented.
3.3.1 Thermodynamics
The values for heat of reaction (∆Hr) in each reactor depend on the type of fuel, type of metal oxide particle utilized, and temperature of the reaction. The sum of the ∆Hr for the overall reaction should be equal to the conventional heat of combustion. The temperatures in each reactor should be less than 1200oC, which will prevent melting of the looping material yet still allow for sufficient reduction-oxidation reactions to occur (Kronberger et al., 2005). This lower temperature will also suppress the formation of NOx during combustion (Ishida and Jin, 1996). The temperature chosen for all calculations is thus 800oC based on the studies by Garcia-Labiano et al. (2006).
The associated ΔHr values for the overall CLC process (along with other fundamental thermodynamic properties) and can be determined from the corresponding reactions occurring in each reactor. When syngas is used as the fuel, NiO(s) is reduced to Ni(s) via the following reaction
2NiO(s) + CO(g) + H2(g) → 2Ni(s) + H2O(g) + CO2(g) [3-4]
in the fuel reactor, and Ni(s) is oxidized to NiO(s) in the air reactor via the following reaction:
2Ni(s) + O2(g) → 2NiO(s) [3-5]
Based on the composition of the syngas to be used, both reactions are spontaneous at 800°C (ΔGr
= -21.7 kJ/mol in the fuel reactor and ΔGr = -140.7 kJ/mol in the air reactor) and exothermic (ΔHr = -17.7 kJ/mol in the fuel reactor and ΔHr = -236.9 kJ/mol in the air reactor) (Atkins and de Paula, 2002; Lide, 2002; Mah and Pankratz, 1976). The overall ΔHr for this particular looping material is -254.6 kJ/mol. To gain insight on NiO’s theoretical ability to provide sufficient oxygen for fuel conversion in a CLC process, the ΔHr for combustion of O2 with the proposed coal-based syngas was compared to the calculated ΔHr when using NiO as the oxygen carrier. The sum of ΔHr for NiO was considered in the comparison since both reactors are sources of heat that can contribute to the overall energy provided by CLC. This comparison, similar to that of Lyngfelt et al. (2001), can be seen in Table 3-3. This table shows that both O2 and NiO can produce almost the same amount of heat from reaction with the coal-based syngas produced from the proposed IGCC, which justifies that NiO-based looping materials can provided just as much or more oxygen needed for CLC systems.
Table 3-3 Comparison of ΔHr for NiO and O2 as applied to CLC at 800oC using previously described syngas
Detailed studies on the conversion of other major looping materials based on their reactivities (e.g., CuO-, Mn2O3-, and Fe2O3-based looping materials) and preparation methods have been performed by several authors (Ishida et al. 1998; Mattisson et al., 2001, 2004, 2005) in the literature.
The occurrence of unwanted side reactions has been considered. The side-reactions theorized to occur within a CLC system include (Ishida et al., 1998; Jin and Ishida, 2004):
CO + H2O → CO2 + H2 [3-6]
CO + 3H2 → CH4 + H2O [3-7]
CH4 + 4NiO → CO2 + 2H2O + 4Ni [3-8]
CH4 → C + 2H2 [3-9]
2CO → C + CO2 [3-10]
Reactions [3-6] and [3-7] are shift and methanation reactions, respectively. Jin and Ishida (2004) have actually confirmed the presence of CH4 in the flue gas of a simulated CLC reactor in which only coal-based syngas was introduced, which justifies the possibility of Reaction [3-7] occurring. The methane produced via Reaction [3-7] can then either react with the metal oxide to form more H2O and CO2 (Reaction [3-8]) or dissociate into C (coke) and H2 (Reaction [3-9]). Furthermore, the CO could potentially dissociate into C and CO2 (Reaction [3-10]). These last two reactions ([3-9] and [3-10]) represent carbon deposition, which is the deposit of carbon onto the looping material. This carbon deposition trend has been confirmed through similar experiments by Ishida et al. (1998) using a thermogravimetric analyzer (TGA) in which a weight gain of the looping material was observed. The deposited carbon is problematic when it is looped to the air reactor where it can react with incoming O2 to form CO2 and consequently decrease reactivity. Jin and Ishida (2004) have confirmed the presence of CO2 during oxidation as a consequence of carbon deposition even though CO2 was not an original input gas. Thermodynamic analysis of the CH4/NiO system over 700-1200°C predicts carbon deposition to be inhibited as long as over 25% excess oxygen needed for complete oxidation of CH4 is supplied via the metal oxide carrier (Mattisson et al., 2006). Ishida et al. (1998) and Jin and Ishida (2004) also found that carbon deposition was avoided when H2O was added to the fuel reactor so that the ratio of H2O to CO is above 0.5. Ultimately the rate of solids circulation must allow the metal oxide particle sufficient time to react with the fuel yet keep it from lingering in the fuel reactor too long to prevent these side reactions from occurring.
3.3.2 Kinetics
Ultimately the kinetics associated with the metal oxide particle when reacted with the fuel affects the oxidation-reduction reaction times. The residence time needed for the metal oxide particles within the proposed reactors can also be affected by the kinetics (discussed in Section 3.4). Therefore, a brief look into the parameters (e.g., metal oxide particle size, temperature within the reactors, and pressure within the reactors) that can affect the kinetics of CLC is presented.
3.3.2.1 Particle Size Influence
The size of the particles used in the reactor has effect on the conversion achieved and also on practical issues of dust formation and material replenishment. It can be intuitively predicted that smaller, powder forms of material offer the highest conversion (higher surface/volume) but have a higher tendency to be swept out of the fluidized reactor. This was confirmed by comparing the studies of Garcia-Labiano et al. (2006) who reported times for complete conversion an order of magnitude less than the conversion times of Jin and Ishida (2004) for CO oxidation using NiO (active oxide) particles 0.7 mm diameter and 1.5 mm size respectively. These experiments were conducted at similar pressure, temperature conditions in thermogravimetric analyzers. Hence, the particle sizes reported to have good conversions and optimum fluidization are in the range of 0.2-
0.7 mm (Kronberger et al., 2005).
3.3.2.2 Temperature Influence
An increase in the reactor temperatures leads to an increase in the oxidation-reduction rates. Cho et al. (2006) have investigated the onset defluidization conditions in fluidized bed reactors (fluidized bed reactors are further explained in Section 3.4) due to agglomeration of the oxygen carrier particles. Based on laboratory scale fluidization testing, they report that agglomeration of Ni-based carriers can be linked to high temperature sintering. Particles sintered above 1600°C during their preparation show quick agglomeration in fluidized beds at approximately 950°C. However, the NiO/NiAl2O4 particle used in this study should not show signs of agglomeration because its sintering temperature during preparation is only 1300°C. Particle preparation methods and operating temperature can be modified to reduce agglomeration.
3.3.2.3 Pressure Influence
Pressurized reactors have been proposed recently as a strategy to reduce reactor sizes for CLC- based power generation systems (Garcia-Labiano et al., 2006; Jin and Ishida, 2004; Wolf et al., 2005). The pressurized TGA studies by Garcia-Labiano et al. (2006) considered the effect of total system pressure on the reaction kinetics in reduction-oxidation conditions. Their findings show a consistent small decrease in reactivity with increasing pressure for both reduction- oxidation reactions when using the NiO/NiAl2O3 particle. Reasoning behind this trend may be attributed to a change in the internal structure (e.g., grain size) of the looping material with varying operating pressures. However, previous studies by Jin and Ishida (2004) using an elevated pressure fixed-bed reactor to compare reactivities of coal-based syngas and CH4 essentially conflict the findings of Garcia-Labiano et al. (2006) and actually claim higher pressures increased reactivity for the oxidation reactions. Thus further studies on the effect of varying pressures on reaction kinetics in the two reactors are needed. Nevertheless, both research groups found that carbon deposition is enhanced at higher pressures (Garcia-Labiano et al., 2006; Jin and Ishida, 2004), which can be further understood on a fundamental level using Le Chatelier’s Principle. In general, based on the side-reactions occurring, the higher pressure would shift Reaction [3-7] to the right towards formation of CH4. Higher pressures would also promote the formation of coke in Reaction [3-10]. A kinetic consequence of these side-reactions occurring is the theoretical reduction in overall oxygen capacity because of the formation of CO2 in the air reactor, which would inevitably increase the time needed for conversion. Garcia- Labiano et al. (2006) also make certain predictions for sulfur containing streams of fuel gas regarding competitive formation of nickel sulfides. Sulfide formation shows high dependence on the pressure of the system.
3.3.2.4 Kinetics Associated with NiO/NiAl2O4
Experimental data taken from Garcia-Labiano et al. (2006) will be used to describe the kinetics associated with the NiO/NiAl2O4 particle to be used for this study. Data was collected using a pressurized TGA at varying pressures (1, 5, 10, 20, and 30 bars) and 800°C with gas streams of either H2, CO, or O2. Although this study did not formally conduct experiments using a combination of the H2 and CO gas streams (representative of a coal-based syngas), relationships between the NiO/NiAl2O4 and the syngas components are still relevant to use for this study. For instance, the reaction rate of the NiO/NiAl2O3 with H2 was always higher than the reaction rate with CO regardless of pressure (Garcia-Labiano et al., 2006). Therefore, the reaction rate for this particular looping material is limited by the reaction rate achieved when using CO. The pressures considered for this CLC system will be 1 bar for simplicity. At these conditions, the estimated times for nearly 100% solid conversion are approximately 0.25 minutes when 5-70% volume H2 is the reducing gas, 0.5 minutes when 5-70% volume CO is the reducing gas, and 0.5 minutes when 5-21% volume O2 is the oxidizing gas.
3.4 Reactor Design
The CLC process remained a theoretical concept for several years since it was first proposed and many studies were merely testing the reactivity and characteristics of oxide carriers using fixed bed and TGA studies (see Jin and Ishida, 2004, Lyngfelt et al., 2001 and references therein). Recently, the CLC process has been successfully demonstrated on a 10 kW scale as part of a project by a European consortium in the GRACE project (Lyngfelt and Thunman, 2005). Johansson et al. (2006) also designed and built a continuous operating laboratory-scale CLC system, which produces up to 300 Wth. Also as part of the GRACE project, conceptual costing studies have been performed in a circulating fluidized bed boiler of a 200 MWe scale (Adanez et al., 2005).
Based on the several issues addressed in the previous sections the proposed CLC power generation system is formed of fluidized bed reactors and a steam cycle combination. Both the air reactor and the fuel reactor are chosen to be cylindrical reactors for simplicity. The air reactor usually has slighly faster conversion rates than the fuel reactor (Lyngfelt et al., 2001). This implies that the reactor height in the air reactor can be higher and faster velocities can be employed in the air reactor to achieve good throughput. The auxiliary power requirement of the IGCC is about 61 MWe and additional gas handling systems require about 40-50 MWe typically so it was planned to generate about 150 MWe of electrical power using the CLC system. The CLC system is also incorporated in the plant design to serve as technology demonstration unit that can be easily integrated with the existing IGCC gasifier output feeds.
3.4.1 Design Methodology
A full schematic of the system is shown in Figure 3-1 at the end of this section. In designing the system a conservative conversion efficiency of 40% (thermal-to-electric) was chosen as a starting point. This fixes thermal load required from the reactors. Based on reaction enthalpies of the primary reactions occurring in the air and fuel reactors it was seen that the heat output per mole of the active looping material. The reactor dimensions and hydrodynamic conditions were then determined based on the chemical and physical properties of the chosen looping material and the thermal load required from the reactor (Kronberger et al., 2005).
The thermal load and the heat of the reaction in the air reactor are used to determine the bed mass and amount of active NiO required in the reactor. The rate at which the thermal energy is produced to raise steam can be derived from the reaction kinetics. The kinetics of the slower reaction (among air and fuel reactors) determines the required minimum residence time to achieve full conversion of the oxide particle. It was determined from the studies of Garcia- Labiano et al (2006) that a minimum of about 30 seconds of residence time is required by 0.2 mm NiO-based particles in the fuel reactor. This time is the limiting rate determined by the CO- NiO reaction kinetics at pressures of up to 5 bar. Beyond a system pressure of 5 bars, the kinetics is slowed down further so those scenarios are not explored here.
As explained previously (see section 3.2) the oxidizer material is chosen as NiO on an alumina support. The issue of defluidization due to particle agglomeration in the air reactor (Cho et al., 2006) is not expected to be of big concern as the operating temperature (800 ˚C) is expected to be lower than the onset of agglomeration at 950 ˚C.
The steps followed in undertaking the design calculations are as following:
- Find the electrical power to be generated using CLC power plant. This can depend on the end user need or the auxiliary power need of a larger power plant if the CLC plant were to supply the auxiliary power.
- Find thermal power required using an approximate efficiency of thermal to electric conversion. (~ 40% ?)
- Using thermal power, decide how much each reactor can individually contribute to this required thermal power.
- Also find out much bed material is needed for the amount of fuel that flows into the fuel reactor
- Number of moles of metal oxide needed (per sec) = # of moles of fuel/2 (for syngas)
Necessary heat transfer rate (in kW), ΔHred (kJ/mol of fuel) x # of moles of metal oxide needed per second (mol/s).
Figure 3-1 Schematic process diagram for the NiO/NiAl2O4 chemical-looping power generation system
3.4.2. Other Assumptions in the Design
Complete solids conversion is assumed to occur in both reactors within the residence time of the solids inside the reactor. The minimum residence time is determined using reaction kinetics in the fuel reactor. The difference in residence times between reactors (i.e., AR has shorted residence time than FR) could lead to a problem in the solids flow balance. However, if the air reactor is greater in height the residence time can be adjusted to obtain a uniform flow rate of solids between the two reactors. Since the heat load from the two reactors is substantially different the rate of solids entering and leaving the reactor are determined based on the thermodynamics (heat produced per mole oxide) and the minimum necessary residence time of the solids inside the reactor (100% conversion) The difference in conversion rates calls for optimum design to handle fluctuations of power demand using a minimum circulation rate of about 0.005 kg/m2.s-1 MW-1 (Kronberger et al., 2005). Based on these considerations, a residence time of approximately 30 seconds is chosen to be the optimum time for the conversion reactions of CO on NiAl2O4 (Kronberger et al., 2005). Since the reaction kinetics of CO oxidation are the limiting reactions for a syngas mixture in the CLC process (Jin and Ishida, 2004) this time should ensure near total conversion of the fuel.
Some of the key issues involve solids movement and oxygen transport in CLC. The rate of solids recirculation is governed by 1) amount of oxygen that needs to be transferred from the air reactor, and 2) the amount of heat that needs to be transferred to keep the fuel reactor at a constant temperature. The very important kinetic issue to be considered for the NiO system is that of prevention of carbon formation (Mattisson et al., 2006) which depends on the oxygen availability in the fuel reactor.
The rate of solids circulation and the oxygen availability will play a key role in the prevention of solids deposition on the spent metal particles in the fuel reactor. Hence a 25% excess of metal oxide particles in the reaction zones of the fuel reactor will be used to limit carbon formation in the fuel reactor. This consideration adds a large bulk to the bed mass. However, this seems to be the most viable solution at present. Figure 3.1 shows a schematic of the CLC system along with some process conditions and illustrated flow rates for a system running to produce 375 MWth power.
Table 3-5 shows the preliminary design parameters of the CLC power generation system. These are preliminary design parameters to plan a conceptual system to provide the thermal load.
Table 3-5 Design parameters of CLC system
The bed inventory shown in Table 3-5 reflects the mass of the composite looping material particles based on a 40:60 ratio of active to binder particles. Another consideration not addressed in detail currently include those of particle life (i..e., attrition and subsequent elutriation). Based on 300 hour batch studies of Adanez et al. (2005) it has been shown that the particles could have a life of about 4000 h prior to being blown away from the system. Furthermore steam cycle calculations and heat exchanger calculations would be based on Rankine cycle calculations provided (Similar to that in Appendix H for IGCC). The particle transport from fuel reactor to the air reactor is by pneumatic conveyance. However the particle transport from AR to FR is gravity driven.
3.5 Design Summary
In summary, the CLC reactor design is proposed as a conceptual design to evaluate indirect combustion technology which achieves higher efficiency (than conventional combustion). However, several issues need to be analyzed in detail especially with respect to the scaling-up process and the mechanical ageing of the looping materials before successful implementation can be achieved. Since chemical-looping shows promise for the future especially with respect to inherent CO2 separation it has been included in the project design scenario.
3.6 Environmental Issues
A major issue with all power generating sources is the concern over the release of harmful emissions and/or solid chemicals to the atmosphere. Both environmental issues as applied to CLC systems will be discussed in this section.
While the focus of this research is primarily on the capture of CO2, the potential for other emissions (e.g., NOx, SOx) from a CLC process must be established. It is often the incomplete conversion of fuels that leads to the release of combustible matter into the atmosphere, which must be environmentally regulated. Higher reactor temperatures (>1200oC) can also increase the production of these harmful emissions (Ishida et al., 2005; Lyngfelt et al., 2001). Even with incomplete conversion of fuel in a CLC process, the generalized results using circulating fluidized bed reactors in the Lyngfelt et al. (2001) study indicate that there is no threat of releasing combustible matter to the atmosphere. This is based on the fact that the air input for the air reactor does not contain combustibles, and there is no gas being emitted from the fuel reactor because after the H2O and CO2 have been condensed any remaining combustible gases will be recirculated back into the fuel reactor. The formation of NOx is also nil since reaction temperatures are less than 1200oC (Ishida and Jin, 1996).
However, the looping materials may contribute to harmful emissions during a CLC process. Regarding this study, Ni-based compounds are listed as hazardous air pollutants by the EPA and are considered one of the greatest chemical threats to public health (EPA, 2005). Therefore, any disposal of the looping materials must be environmentally regulated. Installing filters to reduce any metal particle fragments from unintentionally exiting with the outlet gases of either reactor is encouraged. It is more of an environmental concern when the looping materials are eventually replaced to maintain good reactivity within each reactor that they may be introduced to the environmental surroundings (Lyngfelt et al., 2001). Therefore, using environmentally sound, or non-toxic, looping materials will be important when proposing large-scale CLC systems. The question of releasing the exhausted looping materials into the environment or treating them has not been considered in the literature but must be considered since there are some potential environmental concerns associated with the Ni-based looping materials. Research associated with this area is suggested.
Chapter 4: CO2 Transportation, Safety and Public Perception
Commercialization of CO2 capture from power plants and its subsequent storage or utilization calls for an infrastructure for the transportation, legal frame work and acceptance by the public. Most of the research on CO2 capture and storage deals with capture technologies and their storage possibilities in Enhanced Oil Recovery (EOR) applications (Svensson et al., 2005). The CO2 captured from a power plant represents a large volume, low value byproduct that cannot be disposed as most coal utilization wastes are disposed.
4.1 Transportation and Safety Issues
CO2 is a non toxic gas but can be fatal at concentrations exceeding 10 Vol% as it is heavier than air and tends to accumulate in depressions thus posing a threat of asphyxiation. The public, especially local people where source of CO2 or CO2 storages are located at, become anxious regardless of situation. The statistics from the EOR industry indicate that the risks for leakage in CO2 pipelines are lower than that of natural gas pipelines but nevertheless should be route away from large centers of population (Gale and Davidson, 2002). Further details concerning gas transportation can be found in Appendix I. Risky facilities bother people around it with explosion, pollution, waste transfer and storage risks. Power plants are one of those facilities with their dangerous fuels, pollutant flue gases and high pressured storages. For a coal-fired IGCC as in our specific situation coal as a fuel source bears pollution risk for the environment and captured CO2 becomes another problem with its storage in facility and its highly pressurized transfer pipelines.
4.2 Public Perception
The public perception concerning the storage of CO2 is another major issue which can indirectly affect the transportation. The onshore storage is believed to face difficulties with acceptance from the public who may be open to the idea of onshore storage but not anywhere near their neighborhoods. The public may support the offshore storage on the basis of leakage. The only advantage of having an onshore site is the location near the emission source. Also, economically, offshore disposal requires a complex and costly logistic infrastructure with more expensive disposal facilities (Svensson et al., 2004). Public gets sensitive due to lack of information and education in such cases. Protests, boycotts and rejections are getting solid defense of people and receive significant attention. Consequently some power plants can end up with getting closed.
Even though there are not enough studies that have been done on these issues, some of them give significant information about how people consider the problem and what the solution could be. According to previous studies and questionnaires; answers those are given by public pointed that people do know the necessity of power plants, global warming issue, and accept them with risks but not in their back yard. Reason is usually so clear; risks those power plant bear. On the other hand they do not know how those risks are eliminated or can be eliminated technically. Education is in the heart of problem.
Informative meetings to acquaint people with general and technical issues and precautions those are already maintained must be the starting point. Maintained safety in every step of power plant is a proof of guarantee that company provides and makes people confident about what the risks are and how they are eliminated. Especially for such a power plant where CO2 captured, it would be good to talk about how this can help with daily life and especially about global warming.
If people do not have sufficient information about some thing, then they believe trusted agencies and their reports. This way can be another solution for public education since it is not easy to explain all technical aspects to people on the street. Associating with a trusted company and having a report saying that power plant meets all safety regulations can help to negotiate with public.
Chapter 5: Project Summary
5.1 Conclusions
The overall synthesis of this project resulted in the recommendation of a CO2 capture enabled power plant that is directed towards a futuristic hydrogen based power generation system. The primary power generation source was an integrated combined gasification plant. Coal was used as the gasification feedstock for producing a hydrogen-rich fuel stream that is fired in a gas turbine. The current design operates on combined cycle technology (components: gasifiers, gas turbines, HRSG’s and steam turbines) and incorporates advanced H2/CO2 separation systems (i.e., Pd-based separation membranes), which can recover nearly 100% of the CO2 generated from the 500 MWe IGCC power plant. The efficiency of power generation of the proposed system with CO2 capture is approximately 35%, which is comparable to existing plants without CO2 capture (~34%). The preliminary findings however do not take into account the full penalties or benefits of particle cleanup and heat exchanger operations. It is also noted that the large amount of CO (~12.5% v/v) present in the flue gas is a problem. This CO is a valuable energy source that can be recovered and is also a toxic gas.
Evaluation of new technologies complementary to gasification-based technologies seems to be the direction of coal utilization in the future. In this respect CLC technology to complement IGCC was considered. CLC systems have been projected to have higher efficiencies than IGCC with CO2 capture (Nsakala et al., 2001). Hence an integration of CLC with IGCC can slightly improve system efficiency by approximately 0.3%.
5.2 Recommendations for Future Work
There is a lot of scope for improvement on the present design that considered 100% CO2 capture. However, more efficient power generation can be achieved by modifying the design for a lower percentage of CO2 capture. Different scenarios could include reduction in clean-up penalties by direct combustion the syngas in oxy-fired gas turbines. Use of syngas in advanced fuel cell technologies such as SOFC systems also show promise for efficiency improvements. The hydrogen-rich streams obtained with Pd-based membranes can also be used in the emerging marketplace for fuel cell applications, which adds to the flexibility of the IGCC plant. It is also noted that preliminary calculations predict an IGCC system with post-combustion absorption systems might yield better efficiencies than pre-combustion separations. The unused CO in the flue gas stream presents a valuable energy resource that is currently being lost. The energy from CO can either be recovered in a catalytic burner or the initial CO production can be lowered. Possible ways to reduce CO amounts from the WGS include: 1) increasing steam ratios; or 2) reducing the reaction temperature. Another possible approach is to use a water-gas-shift membrane reactor (Huang et al., 2005), which can replace the Pd-based membrane considered for our design.
Source: Montana Governor’s Office of Economic Development
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