Global warming along with the climate change derived from the World's demand for energy are among the greatest challenges to our society. To tackle climate change issue, research must focus on proposing practical approaches for carbon emissions reduction and environmental remediation. This thesis focuses on carbon dioxide separation mainly from flue gases (major sources of carbon dioxide emissions) using metal organic frameworks (MOFs) to reduce its impact on the global warming hence the climate change. MOFs are a class of crystalline porous adsorbents with structures that attract CO2 selectively and store it in their porous frameworks. Over the course of this PhD research, the fundamental aspects of these materials, as well as their practical applications, have been investigated. For example, the synthesis recipe of copper (II) benzene-1,3,5-tricarboxylate (CuBTC) MOF was improved to deliver a product of high yield ( > 89%) and free of by-product. Also, a mechanism study on the hydrothermal stability CuBTC MOF was carried out under simulated flue gas conditions and delivered the first experimental proof of the decomposition mechanism of CuBTC MOF caused by the water vapour. The fundamental understanding of the stability of materials then motivated the research into the development of a facile method of using an economic functional dopant (i.e. glycine) to strengthen the structure of CuBTC MOF (completely stable towards water vapour), as well as to improve the selectivity of resulting materials to CO2 (by 15% in comparison to the original CuBTC MOF). The suitability of the CuBTC MOF for fixed bed adsorption processes was also assessed using a combined experimental and process simulation method. In addition to the experimental approaches, molecular simulation based on grand canonical Monte Carlo method was also used to understand the effect of structural defects of MOFs on the CO2 adsorption isotherms.

The cryogenic carbon capture™ (CCC) process provides energy- and cost-efficient carbon capture and can be configured to provide an energy storage system using an open-loop natural gas (NG) refrigeration system, which is called energy storing cryogenic carbon capture (CCC-ES™). This investigation focuses on the transient operation and especially on the dynamic response of this energy storage system and explores its efficiency, effectiveness, design, and operation. This investigation included four tasks.The first task explores the steady-state design of four different natural gas liquefaction processes simulated by Aspen HYSYS. These processes differ from traditional LNG process in that the CCC process vaporizes the LNG and the cold vapors return through the LNG heat exchangers, exchanging sensible heat with the incoming flows. The comparisons include costs and energy performance with individually optimized processes, each operating at three operating conditions: energy storage, energy recovery, and balanced operation. The second task examines steady-state and transient models and optimization of natural gas liquefaction using Aspen HYSYS. Steady-state exergy and heat exchanger efficiency analyses characterize the performance of several potential systems. Transient analyses of the optimal steady-state model produced most of the results discussed here. The third task explores transient Aspen HYSYS modeling and optimization of two natural gas liquefaction processes and identifies the rate-limiting process components during load variations. Novel flowrate variations included in this investigation drive transient responses of all units, especially compressors and heat exchangers. Model-predictive controls (MPC) effectively manages such heat exchangers and compares favorably with results using traditional controls. The last task shows how an unprocessed natural gas (NG) pretreatment system can remove more than 90% of the CO2 from NG with CCC technology using Aspen Plus simulations and experimental data. This task shows how CCC-based technology can treat NG streams to prepare them for LNG use. Data from an experimental bench-scale apparatus verify simulation results. Simulated results on carbon (CO2) capture qualitatively and quantitatively agree with experimental results as a function of feedstock properties.

Green chemistry principles have been applied to the enhancement of two industrial chemistry problems. An industrially used reaction to form alcohols from aldehydes and ketones, the Meerwein-Ponndorf-Verley reduction, was improved by introducing a new catalyst Al(OtBu)₃. Due to the lower state of aggregation of this catalyst versus the conventional Al(OiPr)₃ catalyst, reduction rates were found to be faster in both pure iPrOH and mixed solvent systems for three model compounds: benzaldehyde, acetophenone, and a complex, chiral ketone, (S)-CMK. This allowed for the successful implementation of two important milestones; lowering the amount of catalyst needed necessary to complete the reactions (an economic benefit and lower waste) and the conversion from traditional batch reactions to continuous flow (a processing benefit) whereby reactions can be scaled-out rather than scaled-up. Another industrially important field of research that was focused on was CO₂ capture. High energy demands from current CO₂ capture methods such as aqueous amine solvents, specifically from coal-fired power plant flue gas, led to the development of non-aqueous reversible ionic liquids based on silylated amines. Structural modifications of the substitution around the silicon atom, the length of the alkyl chain bonding the silicon and amine, branching along the alkyl backbone, and investigating secondary and primary amines within this class of silylated amines were completed. These amines were reacted with CO₂ and the CO₂ capacity, the ionic liquid viscosity, reversal temperature and reaction enthalpy were all considered as a function of structure. In all cases the capacity was found to be not only greater than that of monethanolamine, an industrial standard, but higher than theoretical predictions through the formation of carbamic acid. Viscosity, reversal temperature, and reaction enthalpy were all found to be tunable through structure. These modifications gave significant insight into the necessary direction for optimization of these solvents as energy-efficient replacements of current CO₂ capture technology.

Optimal operation of plants is becoming more important due to increasing competition and small and changing profit margins for many products. One major reason has been the realization by industry that potentially large savings can be achieved by improving processes. Growth rates and profitability are much lower now, and international competition has increased greatly. The industry is faced with a need to manufacture quality products, while minimizing production costs and complying with a variety of safety and environmental regulations. As industry is confronted with the challenge of moving toward a clearer and more sustainable path of production, new technologies are needed to achieve industrial requirements. In this research, a new methodology is proposed to integrate so-called new technologies into existing processes. Research shows that the new technologies must be carefully selected and adopted to match the complex requirements of an existing process. The new proposed methodology is based on four major steps. If the improvement in the process is not sufficient to meet business needs, new technologies can be considered. Application of a new technology is always perceived as a potential threat; therefore, financial risk assessment and reliability risk analysis help alleviate risk of investment. An industrial case study from the literature was selected to implement and validate the new methodology. The case study is a planning problem to plan the layout or design of a fleet of generating stations owned and operated by the electric utility company, Ontario Power Generation (OPG). The impact of new technology integration on the performance of a power grid consisting of a variety of power generation plants was evaluated. The reduction in carbon emissions is projected to be accomplished through a combination of fuel switching, fuel balancing and switching to new technologies: carbon capture and sequestration. The fuel-balancing technique is used to decrease carbon emissions by adjusting the operation of the fleet of existing electricity-generating stations; the technique of fuel-switching involves switching from carbon-intensive fuels to less carbon-intensive fuels, for instance, switching from coal to natural gas; carbon capture and sequestration are applied to meet carbon emission reduction requirements. Existing power plants with existing technologies consist of fossil fuel stations, nuclear stations, hydroelectric stations, wind power stations, pulverized coal stations and a natural gas combined cycle, while hypothesized power plants with new technologies include solar stations, wind power stations, pulverized coal stations, a natural gas combined cycle and an integrated gasification combined cycle with and without capture and sequestration. The proposed methodology includes financial risk management in the framework of a two stage stochastic programme for energy planning under uncertainty: demands and fuel price. A deterministic mixed integer linear programming formulation is extended to a two-stage stochastic programming model in order to take into account random parameters, which have discrete and finite probabilistic distributions. Thus, the expected value of the total costs of power generation is minimized, while the objective of carbon emission reduction is achieved. Furthermore, conditional value at risk (CVaR), a most preferable risk measure in the financial risk management, is incorporated within the framework of two-stage mixed integer programming. The mathematical formulation, which is called mean-risk model, is applied for the purpose of minimizing expected value. The process is formulated as a mixed integer linear programming model, implemented in GAMS (General Algebraic Modeling System) and solved using the CPLEX algorithm, a commercial solver embedded in GAMS. The computational results demonstrate the effectiveness of the proposed new methodology. The optimization model is applied to an existing Ontario Power Generation (OPG) fleet. Four planning scenarios are considered: a base load demand, a 1.0% growth rate in demand, a 5.0% growth rate in demand, a 10% growth rate in demand and a 20% growth rate in demand. A sensitivity analysis study is accomplished in order to investigate the effect of parameter uncertainties, such as uncertain factors on coal price and natural gas price. The optimization results demonstrate how to achieve the carbon emission mitigation goal with and without new technologies, while minimizing costs affects the configuration of the OPG fleet in terms of generation mix, capacity mix and optimal configuration. The selected new technologies are assessed in order to determine the risks of investment. Electricity costs with new technologies are lower than with the existing technologies. 60% CO2 reduction can be achieved at 20% growth in base load demand with new technologies. The total cost of electricity increases as we increase CO2 reduction or increase electricity demand. However, there is no significant change in CO2 reduction cost when CO2 reduction increases with new technologies. Total cost of electricity increases when fuel price increases. The total cost of electricity increases with financial risk management in order to lower the risk. Therefore, more electricity is produced for the industry to be on the safe side.

Optimal operation of plants is becoming more important due to increasing competition and small and changing profit margins for many products. One major reason has been the realization by industry that potentially large savings can be achieved by improving processes. Growth rates and profitability are much lower now, and international competition has increased greatly. The industry is faced with a need to manufacture quality products, while minimizing production costs and complying with a variety of safety and environmental regulations. As industry is confronted with the challenge of moving toward a clearer and more sustainable path of production, new technologies are needed to achieve industrial requirements. In this research, a new methodology is proposed to integrate so-called new technologies into existing processes. Research shows that the new technologies must be carefully selected and adopted to match the complex requirements of an existing process. The new proposed methodology is based on four major steps. If the improvement in the process is not sufficient to meet business needs, new technologies can be considered. Application of a new technology is always perceived as a potential threat; therefore, financial risk assessment and reliability risk analysis help alleviate risk of investment. An industrial case study from the literature was selected to implement and validate the new methodology. The case study is a planning problem to plan the layout or design of a fleet of generating stations owned and operated by the electric utility company, Ontario Power Generation (OPG). The impact of new technology integration on the performance of a power grid consisting of a variety of power generation plants was evaluated. The reduction in carbon emissions is projected to be accomplished through a combination of fuel switching, fuel balancing and switching to new technologies: carbon capture and sequestration. The fuel-balancing technique is used to decrease carbon emissions by adjusting the operation of the fleet of existing electricity-generating stations; the technique of fuel-switching involves switching from carbon-intensive fuels to less carbon-intensive fuels, for instance, switching from coal to natural gas; carbon capture and sequestration are applied to meet carbon emission reduction requirements. Existing power plants with existing technologies consist of fossil fuel stations, nuclear stations, hydroelectric stations, wind power stations, pulverized coal stations and a natural gas combined cycle, while hypothesized power plants with new technologies include solar stations, wind power stations, pulverized coal stations, a natural gas combined cycle and an integrated gasification combined cycle with and without capture and sequestration. The proposed methodology includes financial risk management in the framework of a two stage stochastic programme for energy planning under uncertainty: demands and fuel price. A deterministic mixed integer linear programming formulation is extended to a two-stage stochastic programming model in order to take into account random parameters, which have discrete and finite probabilistic distributions. Thus, the expected value of the total costs of power generation is minimized, while the objective of carbon emission reduction is achieved. Furthermore, conditional value at risk (CVaR), a most preferable risk measure in the financial risk management, is incorporated within the framework of two-stage mixed integer programming. The mathematical formulation, which is called mean-risk model, is applied for the purpose of minimizing expected value. The process is formulated as a mixed integer linear programming model, implemented in GAMS (General Algebraic Modeling System) and solved using the CPLEX algorithm, a commercial solver embedded in GAMS. The computational results demonstrate the effectiveness of the proposed new methodology. The optimization model is applied to an existing Ontario Power Generation (OPG) fleet. Four planning scenarios are considered: a base load demand, a 1.0% growth rate in demand, a 5.0% growth rate in demand, a 10% growth rate in demand and a 20% growth rate in demand. A sensitivity analysis study is accomplished in order to investigate the effect of parameter uncertainties, such as uncertain factors on coal price and natural gas price. The optimization results demonstrate how to achieve the carbon emission mitigation goal with and without new technologies, while minimizing costs affects the configuration of the OPG fleet in terms of generation mix, capacity mix and optimal configuration. The selected new technologies are assessed in order to determine the risks of investment. Electricity costs with new technologies are lower than with the existing technologies. 60% CO2 reduction can be achieved at 20% growth in base load demand with new technologies. The total cost of electricity increases as we increase CO2 reduction or increase electricity demand. However, there is no significant change in CO2 reduction cost when CO2 reduction increases with new technologies. Total cost of electricity increases when fuel price increases. The total cost of electricity increases with financial risk management in order to lower the risk. Therefore, more electricity is produced for the industry to be on the safe side.

Many geoscientists endorse Carbon Capture and Storage (CCS) as a potential strategy for mitigating emissions of greenhouse gases. Deep saline aquifers have been reported to have larger CO 2 storage capacity than other formation types because of their availability worldwide and less competitive usage. This work proposes an analytical model for screening potential CO 2 storage sites and investigates injection strategies that can be employed to enhance CO 2 storage. The analytical model provides of estimates CO 2 storage efficiency, formation pressure profiles, and CO 2 –brine interface location. The results from the analytical model were compared to those from a sophisticated and reliable numerical model (TOUGH 2 ). The models showed excellent agreement when input conditions applied in both were similar. Results from sensitivity studies indicate that the agreement between the analytical model and TOUGH2 strongly depends on irreducible brine saturation, gravity and on the relationship between relative permeability and brine saturation. A series of numerical experiments have been conducted to study the pros and cons of different injection strategies for CO 2 storage in confined saline aquifers. Vertical, horizontal, and joint vertical and horizontal injection wells were considered. Simulations results show that horizontal wells could be utilized to improve CO 2 storage capacity and efficiency in confined aquifers under pressure-limited conditions with relative permeability ratios greater than or equal to 0:01. In addition, joint wells are more efficient than single vertical wells and less efficient than single horizontal wells for CO 2 storage in anisotropic aquifers.

Carbon capture and storage technologies are necessary to start lowering greenhouse gas emissions while continuing to utilize existing thermal power generation infrastructure. Calcium looping is a promising technology based on cyclic calcination/carbonation reactions which utilizes limestone as a sorbent. Steam is present in combustion flue gas and in the calciner used for sorbent regeneration. The effect of steam during calcination on sorbent performance has not been extensively studied in the literature. Here, experiments were conducted using a thermogravimetric analyzer (TGA) and subsequently a dual-fluidized bed pilot plant to determine the effect of steam injection during calcination on sorbent reactivity during carbonation. In a TGA, various levels of steam (0-40% vol.) were injected during sorbent regeneration throughout 15 calcination/carbonation cycles. All concentrations of steam were found to increase sorbent reactivity during carbonation. A level of 15% steam during calcination had the largest impact. Steam changes the morphology of the sorbent during calcination, likely by shifting the pore volume to larger pores, resulting in a structure which has an increased carrying capacity. This effect was then examined at the pilot scale to determine if the phase contacting patterns and solids heat-up rates in a fluidized bed were factors. Three levels of steam (0%, 15%, 65%) were injected during sorbent regeneration throughout 5 hours of steady state operation. Again, all levels of steam were found to increase sorbent reactivity and reduce the required sorbent make-up rate with the best performance seen at 65% steam.

The global market for membrane separation technologies is forecast to reach $16 billion by the year 2017 due to wide adoption of the membrane technology across various end-use markets. With the growth in demand for high quality products, stringent regulations, environmental concerns, and exhausting natural resources, membrane separation technologies are forecast to witness significant growth over the long term (Global Industry Analysts Inc., 2011). The future of membrane technology promises to be equally exciting as new membrane materials, processes and innovations make their way to the marketplace. The current trend in membrane gas separation industry is, however, to develop robust membranes, which exhibit superior separation performance, and are reliable and durable for particular applications. Process simulation allows the investigation of operating and design variables in the process, and in new process configurations. An optimal operating condition and/or process configuration could possibly yield a better separation performance as well as cost savings. Moreover, with the development of new process concepts, new membrane applications will emerge. The thesis addresses developing models that can be used to help in the design and operation of CO2 capture processes. A mathematical model for the dynamic performance of gas separation with high flux, asymmetric hollow fiber membranes was developed considering the permeate pressure build-up inside the fiber bore and cross flow pattern with respect to the membrane skin. The solution technique is advantageous since it requires minimal computational effort and provides improved solution stability. The model predictions and the robustness of the numerical technique were validated with experimental data for several membrane systems with different flow configurations. The model and solution technique were applied to investigate the performance of several membrane module configurations for air separation and methane recovery from biogas (landfill gas or digester gas). Recycle ratio plays a crucial role, and optimum recycle ratios vital for the retentate recycle to permeate and permeate recycle to feed operation were found. From the concept of two recycle operations, complexities involved in the design and operation of continuous membrane column were simplified. Membrane permselectivity required for a targeted separation to produce pipeline quality natural gas by methane-selective or nitrogen-selective membranes was calculated. The study demonstrates that the new solution technique can conveniently handle the high-flux hollow fiber membrane problems with different module configurations. A section of the study was aimed at rectifying some commonly believed perceptions about pressure build-up in hollow fiber membranes. It is a general intuition that operating at higher pressures permeates more gases, and therefore sometimes the membrane module is tested or characterized at lower pressures to save gas consumption. It is also perceived that higher pressure build-up occurs at higher feed pressures, and membrane performance deteriorates at higher feed pressures. The apparent and intrinsic permeances of H2 and N2 for asymmetric cellulose acetate-based hollow fiber membranes were evaluated from pure gas permeation experiments and numerical analysis, respectively. It was shown that though the pressure build-up increases as feed pressure increases, the effect of pressure build-up on membrane performance is actually minimized at higher feed pressures. Membrane performs close to its actual separation properties if it is operated at high feed pressures, under which conditions the effect of pressure build-up on the membrane performance is minimized. The pressure build-up effect was further investigated by calculating the average loss and percentage loss in the driving force due to pressure build-up, and it was found that percentage loss in driving force is less at high feed pressures than that at low feed pressures. It is true that unsteady state cyclic permeation process can potentially compete with the most selective polymers available to date, both in terms selectivity and productivity. A novel process mode of gas separation by means of cyclic pressure-vacuum swings for feed pressurization and permeate evacuation using a single pump was evaluated for CO2 separation from flue gas. Unlike transient permeation processes reported in the literature which were based on the differences in sorption uptake rates or desorption falloff rates, this process was based on the selective permeability of the membrane for separations. The process was analyzed to elucidate the working principle, and a parametric study was carried out to evaluate the effects of design and operating parameters on the separation performance. It was shown that improved separation efficiency (i.e., product purity and throughput) better than that of conventional steady-state permeation could be obtained by means of pressure-vacuum swing permeation. The effectiveness of membrane processes and feasibility of hybrid processes combining membrane permeation and conventional amine absorption process were investigated for post-combustion CO2 capture. Traditional MEA process uses a substantial amount of energy at the stripper reboiler when CO2 concentration increases. Several single stage and multi-stage membrane process configurations were simulated for a target design specification aiming at possible application in enhanced oil recovery. It was shown that membrane processes offer the lowest energy penalty for post-combustion CO2 capture and likely to expand as more and more CO2 selective membranes are developed. Membrane processes can save up to 20~45% energy compared to the stand-alone MEA capture processes. A comparison of energy perspective for the CO2 capture processes studied was drawn, and it was shown that the energy requirements of the hybrid processes are less than conventional MEA processes. The total energy penalty of the hybrid processes decreases as more and more CO2 is removed by the membranes.

The global market for membrane separation technologies is forecast to reach $16 billion by the year 2017 due to wide adoption of the membrane technology across various end-use markets. With the growth in demand for high quality products, stringent regulations, environmental concerns, and exhausting natural resources, membrane separation technologies are forecast to witness significant growth over the long term (Global Industry Analysts Inc., 2011). The future of membrane technology promises to be equally exciting as new membrane materials, processes and innovations make their way to the marketplace. The current trend in membrane gas separation industry is, however, to develop robust membranes, which exhibit superior separation performance, and are reliable and durable for particular applications. Process simulation allows the investigation of operating and design variables in the process, and in new process configurations. An optimal operating condition and/or process configuration could possibly yield a better separation performance as well as cost savings. Moreover, with the development of new process concepts, new membrane applications will emerge. The thesis addresses developing models that can be used to help in the design and operation of CO2 capture processes. A mathematical model for the dynamic performance of gas separation with high flux, asymmetric hollow fiber membranes was developed considering the permeate pressure build-up inside the fiber bore and cross flow pattern with respect to the membrane skin. The solution technique is advantageous since it requires minimal computational effort and provides improved solution stability. The model predictions and the robustness of the numerical technique were validated with experimental data for several membrane systems with different flow configurations. The model and solution technique were applied to investigate the performance of several membrane module configurations for air separation and methane recovery from biogas (landfill gas or digester gas). Recycle ratio plays a crucial role, and optimum recycle ratios vital for the retentate recycle to permeate and permeate recycle to feed operation were found. From the concept of two recycle operations, complexities involved in the design and operation of continuous membrane column were simplified. Membrane permselectivity required for a targeted separation to produce pipeline quality natural gas by methane-selective or nitrogen-selective membranes was calculated. The study demonstrates that the new solution technique can conveniently handle the high-flux hollow fiber membrane problems with different module configurations. A section of the study was aimed at rectifying some commonly believed perceptions about pressure build-up in hollow fiber membranes. It is a general intuition that operating at higher pressures permeates more gases, and therefore sometimes the membrane module is tested or characterized at lower pressures to save gas consumption. It is also perceived that higher pressure build-up occurs at higher feed pressures, and membrane performance deteriorates at higher feed pressures. The apparent and intrinsic permeances of H2 and N2 for asymmetric cellulose acetate-based hollow fiber membranes were evaluated from pure gas permeation experiments and numerical analysis, respectively. It was shown that though the pressure build-up increases as feed pressure increases, the effect of pressure build-up on membrane performance is actually minimized at higher feed pressures. Membrane performs close to its actual separation properties if it is operated at high feed pressures, under which conditions the effect of pressure build-up on the membrane performance is minimized. The pressure build-up effect was further investigated by calculating the average loss and percentage loss in the driving force due to pressure build-up, and it was found that percentage loss in driving force is less at high feed pressures than that at low feed pressures. It is true that unsteady state cyclic permeation process can potentially compete with the most selective polymers available to date, both in terms selectivity and productivity. A novel process mode of gas separation by means of cyclic pressure-vacuum swings for feed pressurization and permeate evacuation using a single pump was evaluated for CO2 separation from flue gas. Unlike transient permeation processes reported in the literature which were based on the differences in sorption uptake rates or desorption falloff rates, this process was based on the selective permeability of the membrane for separations. The process was analyzed to elucidate the working principle, and a parametric study was carried out to evaluate the effects of design and operating parameters on the separation performance. It was shown that improved separation efficiency (i.e., product purity and throughput) better than that of conventional steady-state permeation could be obtained by means of pressure-vacuum swing permeation. The effectiveness of membrane processes and feasibility of hybrid processes combining membrane permeation and conventional amine absorption process were investigated for post-combustion CO2 capture. Traditional MEA process uses a substantial amount of energy at the stripper reboiler when CO2 concentration increases. Several single stage and multi-stage membrane process configurations were simulated for a target design specification aiming at possible application in enhanced oil recovery. It was shown that membrane processes offer the lowest energy penalty for post-combustion CO2 capture and likely to expand as more and more CO2 selective membranes are developed. Membrane processes can save up to 20~45% energy compared to the stand-alone MEA capture processes. A comparison of energy perspective for the CO2 capture processes studied was drawn, and it was shown that the energy requirements of the hybrid processes are less than conventional MEA processes. The total energy penalty of the hybrid processes decreases as more and more CO2 is removed by the membranes.

Carbon capture and storage (CCS) and a point of electricity generation is a promising option for mitigating greenhouse gas emissions. One issue with respect to CCS is the design of carbon dioxide transport, storage and injection system. This dissertation develops a model, OptimaCCS, that combines economic and spatial optimization for the integration of CCS transport, storage and injection infrastructure to minimize costs. The model solves for the lowest-cost set of pipeline routes and storage/injection sites that connect CO2 sources to the storage. It factors in pipeline costs, site-specific storage costs, and pipeline routes considerations involving existing right of ways and land use. It also considers cost reductions resulting from networking the pipelines segment from the plants into trunk lines that lead to the storage sites. OptimaCCS is demonstrated for a system involving carbon capture at 14 Texas coal-fired power plants and three potential deep-saline aquifer sequestration sites. In turn OptimaCCS generates 1) a cost-effective CCS pipeline network for transporting CO2 from all the power plants to the possible storage sites, and 2) an estimate of the costs associated with the CO2 transport and storage. It is used to examine variations in the configuration of the pipeline network depending on differences in storage site-specific injection costs. These results highlight how various levels of cooperation by CO2 emitters and difference in injection costs among possible storage sites can affect the most cost-effective arrangement for deploying CCS infrastructure. This study also analyzes CCS deployment under the features in a piece of legislation the draft of American Power Act (APA) - that was proposed in 2010 which contained a goal of CCS capacity for emissions from 72 Gigawatt (GW) by 2034. A model was developed that simulates CCS deployment while considering different combinations of carbon price trajectories, technology progress, and assumed auction prices. The model shows that the deployment rate of CCS technology under APA is affected by the available bonus allowances, carbon price trajectory, CCS incentive, technological adaptation, and auction process. Furthermore it demonstrates that the 72GW objective can only be achieved in a rapid deployment scenario with quick learning-by-doing and high carbon price starting at 25 dollars in 2013 with a 5 percent annual increase. Furthermore under the slow and moderate deployment scenarios CCS capacity falls short of achieving the 72 GW objective.