Browsing by Subject "Carbon capture"
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Item Amine aerosol in aqueous scrubbing for CO₂ capture(2021-10-01) Akinpelumi, Korede Fiyinfoluwa; Rochelle, Gary T.; Hildebrandt Ruiz, Lea; Bonnecaze, Roger T; Knuutila, Hanna; Chen, EricSustained amine emissions above one ppm are prohibitive to amine scrubbing and prevalent with aerosol in the flue gas. The development, demonstration, and quantification of mitigation strategies for amine aerosol will ensure sustainable CO₂ capture operations. This work supports that goal by conducting systematic aerosol tests and developing aerosol models for 2nd and 3rd generation CO₂ capture solvents. SO₃ generation by catalytic conversion and plasma oxidation of SO₂ were compared and adapted for aerosol tests. The catalytic bed was proven highly effective at pilot scale with the demonstration of 97% conversion and 8 ppm SO₃ injection into 4000 lb/hr flue gas. Plasma oxidation had a much lower conversion but showed great promise due to its relative cost and ease of start-up/shut down. Amine aerosol can be sustainably mitigated upstream of CO₂ capture or within the absorber and water wash and are reduced at NGCC conditions. The hydrated lime addition rate is the critical indicator for upstream SO₃ reduction and inlet aerosol mitigation in baghouse operations. The threshold for SO₃ slippage is at half the normal lime rate. As inlet flue gas SO₃ increases, amine emissions increase, and the water wash performance decreases. There exists a tradeoff between capital or energy costs and amine aerosol control. A 98% reduction in PZ aerosol was demonstrated for flue gas with 2 ppm SO₃ by increasing the lean solvent to 58 °C and using a 2-stage water wash. Particulate measurements showed that PZ aerosol grows and gets collected at higher lean solvent temperatures. The growth of amine aerosol in the absorber is driven by amine-limited diffusion, and the aerosol is in equilibrium with water in the bulk gas phase. More volatile solvents grow bigger drops due to the larger driving force for amine transfer, and the effect of aerosol concentration on drop size is diminished. Therefore, aerosol mitigation with mist eliminators should be feasible for highly volatile solvents. As the volatility of the amine in a solvent system increases, vapor emissions will become more significant than aerosol emissions.Item Carbon capture and storage network optimization under uncertainty(2018-05) Tutton, Peter Mark; Leibowicz, Benjamin D.; Hovorka, Susan D. (Susan Davis)Carbon capture and storage is a method for emissions reductions that can be applied to both the electric sector and industrial sources. Significant uncertainties surround the technologies, policy and extent to which CCS will be deployed in the future. For widespread deployment, future CCS demand should be considered during infrastructure planning. This study presents a novel model that considers spatial information and uncertainty in generating an optimal CCS network. The two-stage stochastic model, utilizes both geographic information systems (GIS) and mixed integer programming (MIP), to generate an optimal near-term hedging strategy. The strategy considers one discrete uncertainty distribution: the future demand for CO₂ storage. A case study in the Texas Gulf Coast demonstrates the value of considering uncertainty of future demand. The optimal solution is selected from a candidate network consisting of twelve sources and five reservoirs that can be linked via a network of pipelines and ship routes. The results demonstrate that optimal hedging strategies lead to transportation cost savings of up to 14% compared to a ‘naive approach’ in which only the expected value is considered. The transportation selection also highlights the benefit of utilizing ship transport in uncertain scenarios due to their ability to be reassigned to a different route or sold.Item Carbon dioxide solubility and mass transfer in aqueous amines for carbon capture(2015-08) Li, Ph. D., Le; Rochelle, Gary T.; Freeman, Benny D; Sanchez, Isaac C; Svendsen, Hallvard F; Dugas, Ross EAmine scrubbing is the state of the art technology for CO2 capture, and solvent selection can significantly reduce the capital and energy cost of the process. This work presents rigorous CO2 mass transfer and solubility data at expected process conditions for more than 20 aqueous amines and amino acid salts. Amino acid salts are generally not competitive with aqueous amines as solvents for CO2 capture, particularly from coal fired power plants. The capacity of amino acid salts is intrinsically low (0.2 – 0.35 mol/mol alkalinity). Piperazine (PZ) blends have good overall performance. 3.5 m PZ/3.5 m 2-amino-2-hydroxymethyl-propane-1,3-diol (Tris) shows good absorption rates, good capacity, and low solvent viscosity. 6 m PZ/2 m hexamethylenediamine (HMDA) has moderate absorption rates, capacity, and a high viscosity. High solvent viscosity has been shown to reduce CO2 absorption rate and increase sensible heat cost. A simplified speciation model (SSM) was developed in MATLAB to represent CO2 VLE in a mono-amine solvent using only four adjustable parameters. The model can also predict liquid phase speciation. Primary and secondary amines were shown to have different CO2 VLE dependence on amine pKa. At pKa higher than 8, secondary amines have lower carbamate stability than primary amines. A correlation was developed to predict the SSM parameters based on the amine type and amine pKa. The third order overall reaction kinetic expression better explains the mass transfer data at process conditions than the more widely applied second order overall expression. A new Bronsted correlation was developed to represent the third order concentration based kinetic constant at 40 °C for primary and secondary amines: 〖log〗_10 (〖k_(c-3)〗^* )=-11.728+1.113∙p〖K_a〗_amine. This work shows the absorption rate of CO2 at process conditions do not always increase with amine pKa. As the reaction rate constant increases with amine pKa, the free amine available for CO2 absorption decreases. As the result, for primary and secondary mono-amines, the optimum amine pKa for the best mass transfer performance is around 8.7 (at 40 °C).Item Design principles and structure-function relations of nitrogen-rich nanoporous carbons(2023-08-11) Burrow, James N.; Mullins, C. B.; Korgel, Brian A; Lynd, Nathaniel A; Yu, GuihuaEfficient separation of CO₂ from post-combustion flue gas remains a significant engineering challenge central to the energy transition. Swing adsorption processes, operating on the principle of selective physisorption, have garnered considerable interest as a potentially sustainable solution for post-combustion carbon capture. This dissertation focuses on understanding synthetic processes, design principles, and structure-function relationships of N-enriched nanoporous carbon adsorbents for the selective capture of CO₂. Using a multimodal material characterization approach centered around gas porosimetry and X-ray techniques, this work has revealed 1) how to alter syntheses to tune porosity, surface chemistry, and nanostructure of carbon adsorbents and 2) which material properties should be targeted for increased CO₂ capacity and selectivity toward practical utility. We showed that the presence of N during synthesis can significantly alter traditional mechanistic pathways of porosity generation, and that the use of molten salts as high-temperature solvent analogues enables precise control of carbon material properties. Further, we found a compensation relationship between the entropy loss and enthalpy gain of CO₂ adsorption, stemming from confinement in carbon nanopores. We revealed that N-rich surface chemistries can effectively break this exchange relation by enhancing the interaction between the sorbent surface and polarizable CO₂ while impacting the configurational entropy to a lesser extent. As such, we identified that the heat of CO₂ adsorption on nanoporous carbons is tunable from approximately 20 – 50 kJ/mol at typical flue gas conditions by manipulating nanostructure and N content. Additionally, we discovered that increases to the CO₂/N₂ adsorption selectivity, indirectly associated with increased N-content, are in fact derived from a molecular sieving effect between turbostratic sheets of carbon that pack tightly enough to exclude N₂ but simultaneously allow for high-affinity CO₂ adsorption. We also emphasized that commonly-pursued design goals of enhancing CO₂ capacity by maximizing (N₂-accessible) microporosity and surface area are in practice associated with deleterious increases in N₂ adsorption and diminished CO₂/N₂ selectivity. As a result, nanoporous carbons with both high capacity and sufficient selectivity for utility in post-combustion carbon capture must present only moderate N₂-accessible surface area with a semi-crystalline nanostructure amenable to molecular sieving, with an interlayer d-spacing (i.e., critical ultramicropore width) between 3.30 and 3.64 Å (the kinetic diameters of CO₂ and N₂, respectively). With a data-driven approach to molten salt synthesis of these size-sieving turbostratic carbons, we employed inverse design to create N-rich carbon adsorbents that satisfy these requirements and obtain predicted performance for carbon capture from natural gas combined cycle flue gas that rivals benchmark metal-organic frameworks (i.e., Mg-MOF-74, UTSA-16). Additionally, we report the discovery of calcium poly(heptazine imide), a covalent organic framework allotrope of carbon nitride. We found that exchanging framework-complexed cations with protons resulted in an amine-rich porous material that selectively captures a large quantity of CO₂ from dilute conditions through enhanced physisorption (and not chemisorption), most likely mediated by H-bonding with acidic protons.Item Dynamic modeling of post-combustion amine scrubbing for process control strategy development(2016-05) Walters, Matthew Scott; Rochelle, Gary T.; Edgar, Thomas F.; Baldea, Michael; Akella, Maruthi R; Chen, EricIntensified process designs with advanced solvents have been proposed to decrease both capital and operating costs of post-combustion carbon capture with amine scrubbing. These advanced flowsheets create process control challenges because process variables are designed to operate near constraints and the degrees of freedom are increased due to heat recovery. Additionally, amine scrubbing is tightly integrated with the upstream power plant and downstream enhanced oil recovery (EOR) facility. This work simulated an amine scrubbing plant that uses an intercooled absorber and advanced flash stripper configuration with aqueous piperazine to capture CO2 from a 550 MWe coal-fired power plant. The objective of this research was to develop a process control strategy that resulted in favorable closed-loop dynamics and near-optimal conditions in response to disturbances and off-design operation. Two models were created for dynamic simulation of the amine scrubbing system: a medium-order model of an intercooled absorber column and a low-order model of the entire plant. The purpose of the medium-order model was to accurately predict the absorber temperature profile in order to identify a column temperature that can be controlled by manipulating the solvent circulation rate to maintain a constant liquid to gas ratio. The low-order model, which was shown to sufficiently represent dynamic process behavior through validation with pilot plant data, was used to develop a plantwide control strategy. A regulatory control layer was implemented and tested with bounding cases that represent either electricity generation requirements, CO2 emission regulations, or EOR constraints dominating the control strategy. Satisfying the operational and economic objectives of one system component was found to result in unfavorable dynamic performance for the remainder of the system. Self-optimizing control variables were identified for the energy recovery flowrates of the advanced flash stripper that maintained good energy performance in off-design conditions. Regulatory control alone could not satisfactorily achieve the set point for CO2 removal rate from the flue gas. A supervisory model predictive controller was developed that manipulates the set point for the stripper pressure controller in order to control removal. The straightforward single-input, single-output constrained linear model predictive controller exhibited a significant improvement compared to PI control alone.Item Evaluation of two potassium-based activation agents for the production of oxygen- and nitrogen-doped porous carbons(2021-03-14) Guerrera, Joseph Vincent Mihm; Mullins, C. B.This work evaluates the use of potassium hydroxide (KOH) and potassium oxalate monohydrate (K₂C₂O₄•H₂O) for the formation of nitrogen- and oxygen-doped porous carbons. Based on molar equivalent amounts of potassium, we find that KOH activation generally produces porous carbons with larger fractions of mesopores (≥ 2 nm), while K₂C₂O₄•H₂O activation produces porous carbons with greater fractions of micropores (≤ 2 nm). Additionally, we investigate mechanisms of heteroatom loss during activation and find that nitrogen is exclusively sequestered in solid inorganic phases. Notably, differences in the surface properties of the resulting carbons are subtle. While surface nitrogen species are similar between both activation treatments, KOH activation produces materials with both a greater abundance and different types of surface oxygen species when compared to K₂C₂O₄•H₂O activation. Finally, we determine that the degree of carbon dioxide (CO₂) adsorbed in the activated carbons at pressures up to 1 bar is primarily determined by the volume of small micropores (≤ 1 nm). Overall, this study seeks to provide a roadmap to tailor the surface and textural properties of heteroatom-doped porous carbons for gas storage, separations, and energy storage applications.Item First-principles studies on degradation of aqueous amines for carbon dioxide capture(2022-04-27) Yoon, Bohak; Hwang, Gyeong S.; Rochelle, Gary T.; Hildebrandt-Ruiz, Lea; Ren, PengyuChemical absorption with aqueous amine-based solvents has been the most promising incumbent technology for post-combustion CO₂ capture from flue gas. However, its extensive operation is severely limited by the large cost attributed to the enormous energy requirement for solvent regeneration and degradation issues leading to makeup of amine solvent loss. First-principles atomistic modeling can provide key insights into elucidating chemical phenomena pertinent to degradation behavior in CO₂-loaded aqueous amine solution, which is often extremely challenging to be experimentally characterized. In this dissertation, our first-principles works on illuminating the molecular mechanisms governing solvent degradation of aqueous amine during CO₂ capture are presented. Using density functional theory based ab initio molecular dynamics with enhanced sampling techniques, we identify elementary reactions governing CO₂ capture and degradation. Molecular mechanisms of thermal and oxidative degradation of aqueous amine solvents are discussed in perspective of both thermodynamics and kinetics. We systematically investigate on the factors prevailing key reaction rates, such as amine functional groups, the steric hindrances, classes of amines (primary and secondary), concentration of amines, solvation nature, and temperature conditions. These factors may largely affect relative strengths of both inter- and intramolecular hydrogen bond interactions in CO₂-loaded aqueous amine solution. Our theoretical studies further illustrate the importance of an atomistic-level description of solvation structure and dynamics that may primarily govern CO₂ reaction with aqueous amine solvents and associated degradation mechanisms. This dissertation highlights the key role of first-principles computational modelling in accurately describing mechanistic understandings on CO₂ capture by aqueous amine solvents and associated degradation processes. The enhanced atomisticlevel descriptions will provide more complete explanations for experimental characterizations and valuable suggestions on how to optimize existing solvents and design more cost-efficient solvents for carbon capture processes.Item Mass transfer rate in semi-aqueous amines for CO₂ capture(2018-08) Yuan, Ye, Ph. D.; Rochelle, Gary T.; Sanchez, Isaac C.; Hwang, Gyeong S.; Dugas, Ross E.Amine scrubbing is the most promising solution to address CO₂ emission from power plants. Solvent development can significantly reduce the capital and energy cost of the process. This work rigorously studies the CO₂ mass transfer and solubility at flue gas treating process condition for aqueous and semi-aqueous amines. A second-generation aqueous amine solvent: 2methylpiperazine (2MPZ) blended with piperazine (PZ) that has been developed with good overall performance. The effect of viscosity on absorption rate and heat exchanger has been identified. Optimal concentration for 2MPZ/PZ is found to be 5 m (5 mole/kg water). Thermodynamic and kinetic model has been developed for 2MPZ/PZ in Aspen Plus to allow economic assessments, and process modeling. Semi-aqueous MEA/PZ composes of physical solvent, water, and amine has been characterized. Ultra-fast absorption rate at lean loading has been achieved. The effect of viscosity, diffusivity, CO₂ activity (physical solubility), and amine activity on mass transfer rate (kg') has been studied. kg' increases because of reduced operating CO₂ loading (higher MEA concentration at the same P [superscript *] [subscript CO2]), greater CO₂ physical solubility, and greater MEA activity. The increase in kg' becomes less significant at higher loading due to low diffusivity by high viscosity. The mass transfer model of CO₂ diffusion and reaction with semi-aqueous MEA was built in MATLAB [superscript ®]. Sensitive analysis shows the relationship between rate and solvent physical/thermal properties. The pseudo first order approximation is not applicable to semi-aqueous MEA because of surface depletion of MEA. The energy use of CO₂ capture by amine scrubbing can be estimated by adding minimum work and lost work. Semi-aqueous amines reduces the lost work in the condenser due to less water evaporation in the stripper, which. However; second generation amine processes use advanced stripper configurations can accomplish the same effect with little additional capital cost. Besides viscosity, thermal conductivity and heat capacity also effect the heat exchanger cost. Comprehensive normalized capacity has been developed. An advanced solvent with high normalized capacity can reduce the CAPEX/OPEX of the heat exchanger no matter the solvent is water lean or not. [Mathematical equation].Item Modeling advanced strippers for CO₂ capture from gas-fired power plants using aqueous piperazine(2023-08-08) Suresh Babu, Athreya; Rochelle, Gary T.; Baldea, Michael; Bonnecaze, Roger; Lin, Yu-Jeng; Tsai, RobertEnergy performance of 5 m piperazine was evaluated with an advanced stripper at the pilot scale, accounting for heat loss. Modeling studies indicated that heat loss at locations other than the heat source impacted the heat duty. For strippers with excess packing, the column was the most important source of heat loss, and values as low as 0.03 GJ/hr can cause pinch and reabsorption of CO₂. Solvents like 5 m PZ are more affected by heat loss in the column due to a top-side temperature pinch at high lean loading. Heat loss impacts NGCC CO₂ capture more than coal-based CO₂ capture. Surface temperature measurements pilot plants showed that heat loss was 50-75% controlled by natural convection. Measured heat loss was correlated with steam flowrate and wind speed and ranged from 8126 to 219668 Btu/hr, representing 35% of the measured heat rate on average. Net heat duty linearly varied with CO₂ removal at low lean loading and was similar for coal and NGCC conditions at fixed removal. At 90% removal, net heat duty was about 2.5 GJ/t with 4 and 12% CO₂ in the flue gas. At NGCC conditions, strippers with finite packing can benefit from a flashing feed to the top of the column by using a hot bypass. A flashing feed was linked to a reduction in irreversibility of the stripper from temperature driving forces. It also reduces heat duty by up to 6% at fixed packing height and reduces packing requirement for a fixed steam heater size compared to a warm bypass. Lean loading and lean solvent rate were effective handles to maximize profitability of a fixed stripper design at low gas price. High ambient temperature operation can benefit from low pressure stripping to about 0.18 lean loading at 150 ℃ to maintain the cyclic capacity at reduced rich loading. At low gas price, the capture plant was able to maximize profitability even with a high heat duty of 2.7-3.1 GJ/t at a lean loading of 0.2-0.22 mol/mol. Heat recovery by partial water vapor condensation in a gas-liquid exchanger can be replaced by a direct contact condenser (DCC). The DCC improved gas cooling and reduced heat duty compared to the CO₂ exchanger at 0.2 lean loading. The DCC when used with a 150 ℃/5.5 bar stripper can reduce the cost of capture compared to the base case by $3- 4/tonne at 15 ft of packing (optimum) but increases cost of capture by $6/tonne with a 120 ℃/2 bar stripper and 10 ft of packing (optimum). The DCC can work effectively with a solvent with a high heat of absorption and thermal stability.Item Modeling of stripper configurations for CO₂ capture using aqueous piperazine(2013-05) Madan, Tarun; Rochelle, Gary T.This thesis seeks to improve the economic viability of carbon capture process by reducing the energy requirement of amine scrubbing technology. High steam requirement for solvent regeneration in this technology can be reduced by improvements in the regeneration process. Solvent models based on experimental results have been created by previous researchers and are available for simulation and process modeling in Aspen Plus®. Standard process modeling specifications are developed and multiple regeneration processes are compared for piperazine (a cyclic diamine) in Chapter 2. The configurations were optimized to identify optimal operating conditions for energy performance. These processes utilize methods of better heat recovery and effective separation and show 2 to 8% improvement in energy requirement as compared to conventional absorber-stripper configuration. The best configuration is the interheated stripper which requires equivalent work of 29.9 kJ/mol CO₂ compared to 32.6 kJ/mol CO₂ for the simple stripper. The Fawkes and Independence solvent models were used for modeling and simulation. A new regeneration configuration called the advanced flash stripper (patent pending) was developed and simulated using the Independence model. Multiple complex levels of the process were simulated and results show more than 10% improvement in energy performance. Multiple cases of operating conditions and process specifications were simulated and the best case requires equivalent work of 29 kJ/mol CO₂. This work also includes modeling and simulation of pilot plant campaigns carried out for demonstration of a piperazine with a 2-stage flash on at 1 tpd CO₂. Reconciliation of data was done in Aspen Plus for solvent model validation. The solvent model predicted results consistent with the measured values. A systematic error of approximately +5% was found in the rich CO₂, that can be attributed to laboratory measurement errors, instrument measurement errors, and standard deviation in solvent model data. Stripper Modeling for CO₂ capture from natural gas combustion was done under a project by TOTAL through the Process Science and Technology Center. Two configurations were simulated for each of three flue gas conditions (corresponding to 3%, 6% and 9% CO₂). Best cases for the three conditions of flue gas require 34.9, 33.1 and 31.6 kJ/mol CO₂.Item Nitrogen dioxide absorption into sulfite inhibited by thiosulfate(2019-08) Suresh Babu, Athreya; Lawler, Desmond F.; Rochelle, GaryEmulsified sulfur was found to be the most suitable form of sulfur for in-situ thiosulfate production for sulfite inhibition with a maximum sulfur-to-thiosulfate-conversion of 50 % and t₅₀ of 6 hours. Increasing the ionic strength of the solution reduces the reaction rate between sulfur and sulfite. Reaction rate reduced by 3 when ionic strength of the solution was increased from 0.225 M to 2.95 M. The rate of reaction between sulfur and sulfite was found to be first-order in sulfur, half-order in sulfite, and zero-order in thiosulfate with a reaction rate constant of 5.48 x 10⁻³ mM [superscript -0.5] min⁻¹. Increasing the reaction temperature from 40 to 75 °C increased the interpreted reaction rate by a factor of 17. The activation energy of the reaction was found to be 74.2 kJ/mol, and this high value indicates that the reaction might be kinetically limited and not mass transfer limited. The reaction rate model predicts experimental bench-scale reaction rates with an absolute average deviation of 6.5%. In the pilot-scale prescrubber, at coal conditions, pH was observed to decrease as a function of time with 3 linear regions. These regions corresponded to CO₂ absorption to form carbonate, conversion of carbonate to bicarbonate, and CO₂ liberation from solution by reaction of bicarbonate with SO₂ respectively. The characteristic times of these linear regions corresponded to the rate of the reaction in each of these regions. Rate of oxidation of thiosulfate under 0-1 ppm NO₂ conditions was 0.13 gmol/hr which was half the rate at 0-5 ppm NO₂ conditions. Thiosulfate loss by tank bleed was found to be directly related to the amount of gas processed. Thiosulfate loss by bleed reduced from 60 gmol to 17.2 gmol when the flue gas flow rate reduced by 1/2.25 due to the lesser amount of water condensing in the prescrubber. A minimum of 25 mM sulfite was required to maintain NO₂ removal of 90% even under low NO₂ conditions. At NGCC conditions, thiosulfate degradation rates were 0.112 gmol/hr and 0.127 gmol/hr before and after thiosulfate addition respectively. Sulfite and thiosulfate in the prescrubber increased with SO₂ coming into the prescrubber. Thiosulfate and sulfite were correlated by a power-law relation just as in the coal conditionItem On the economics of carbon capture(2023-08-11) Stemmler, Joseph Augustin; Stinchcombe, Maxwell; Dorsey, Jackson; Olmstead, Sheila; Waxman, Andrew; Wiseman, ThomasThe four chapters of this dissertation study carbon capture, utilization, and sequestration (CCUS) in a variety of settings. In each chapter, I analyze the behavior that different carbon policy instruments elicit from a polluting firm with CCUS technology available to capture their emissions generated in the production process. In particular, I examine the difference in outcomes between a carbon tax on net emissions and a subsidy system for technologically sequestered carbon representative of recent carbon legislation in the United States (Internal Revenue Code 45Q). In the first chapter, I motivate the study of subsidies in the context of carbon sequestration by considering a dynamic setting in which a firm that sequesters generates future benefits through learning. These future benefits stem from own-learning effects (reducing the cost of sequestration) as well as demonstration effects (other firms learn by observing the viability and profitability of sequestration, and subsequently undertaking it). Using a simple framework, I illustrate the shortcomings of addressing an emerging climate technology solely with carbon-pricing initiatives. I show that when future benefits of these learning "spillovers" are not accounted for, there is a divergence in the societal and private benefits. The additional market failure of the positive learning externality can be accommodated fully by using both carbon pricing and a sequestration subsidy. When only a subsidy is available, as in the case of 45Q, I demonstrate that the early subsidization of sequestration is valuable due to these learning spillovers and the nascency of sequestration technology, and a regulator would be willing to subsidize sequestration even if the sequestration technology initially leads to an increase in net emissions (the technology is "perverse"), so long as the future benefits outweigh the damages from increased net emissions. This chapter establishes the notion of a "perverse" sequestration technology (causing a "cobra effect") and the importance of subsidies for nascent technologies, which is studied extensively in the subsequent chapters. In the second chapter, I study how a carbon tax and a sequestration subsidy alter a polluting firm's production decisions, as well as how much (if any) sequestration the firm decides to undertake. Using a static framework in which a firm imposes a negative emissions externality on society, I investigate which components of the ongoing debate about subsidizing sequestration hold water, and ask ``When subject to a sequestration subsidy, is it possible that net emissions may actually increase?" I find that the answer to this question is "yes," and provide conditions for the pollution intensity of the firm and the cost structure for sequestration technology necessary for this perverse outcome to arise. In the third chapter, I extend the setting of the second chapter by including two market failures: a negative emissions externality from production, and market power within the regulated industry. I characterize the production and sequestration behavior of imperfectly competitive firms subject to either a carbon tax or a sequestration subsidy, and determine whether emissions outcomes tend to worsen or improve when the industry in question is imperfectly competitive. I find that despite producing less aggregate net emissions than their more competitive counterparts, the oligopolists are just as (if not more) prone to the same perverse incentives to over-emit in response to a sequestration subsidy. In the fourth and final chapter, I survey the existing literature on carbon policy with a particular focus on CCUS and subsidy systems. I provide an overview of the current state of the subsidies literature in the realm of environmental economics, and enumerate gaps within the literature that serve as avenues for future research. I find that the literature on environmental subsidy systems beyond the domain of solar and wind energy is thin, and is primarily concentrated within rather dated theory papers. In contrast, the literature on CCUS is almost entirely restricted to engineering or engineering-economics due to large-scale commercial application of CCUS being relatively recent. As a result, there is ample work to be done on evaluating the impact of recent sequestration policy within the US, both in theory as well as empirically as the data from CCUS facilities currently in construction emerge as they are put to use.Item Pilot plant modeling of Advanced Flash Stripper with piperazine(2018-12-07) Selinger, Joseph Leo; Rochelle, Gary T.Implementation of carbon capture using amine scrubbing is limited by the large energy penalty of CO₂ capture and compression. Alternative stripper designs can reduce lost work in the stripper by implementing heat recovery unit operations and reducing opportunities for solvent degradation. The advanced flash stripper (AFS) has reduced the required equivalent work by 12-15% compared to the simple stripper by using multiple solvent bypasses to equalize heat capacity across cross exchangers and minimizing lost latent heat of water vapor in the condenser. The Advanced Flash Stripper using 5 m piperazine was studied at the National Carbon Capture Center (NCCC) pilot plant, which presented the novel opportunity to test the solvent and design configuration with coal-fired power plant flue gas. Piperazine (PZ) solvent was stripped of CO₂ with an average stripper operating temperature of 150 °C The energy cost averaged 2.2 GJ/MT CO₂ for the AFS and 3.8 GJ/MT CO₂ for the simple stripper (SS). A temperature-control heuristic for controlling bypass flowrates was evaluated using five AFS test cases. Using bypass temperature differences of 7 °C, the bypass rates were automatically controlled to within 5% of the optimal bypass configuration. While the method was successful in simulations, unexpected heat loss in the NCCC plant limited the accuracy of the temperature-control heuristic due to the heat loss reducing the benefits of heat recovery unit operations. Overall energy balances of the AFS using the Independence model showed a positive heat gain of 65000 Btu/hr. The unexpected heat gain was attributed to an overestimated heat of absorption in the Independence model, as well as an underestimation of the total heat transferred from the process steam. A test AFS run was analyzed using three different assumption methods, with energy requirements varying from 2.1 – 3.0 GJ/MT CO₂.Item Theoretical studies of aqueous amine solvents for carbon dioxide capture(2018-05) Stowe, Haley Maren; Hwang, Gyeong S.; Henkelman, Graeme; Johnston, Keith P; Ren, Pengyu; Rochelle, Gary TAqueous amine-based chemical scrubbing has been considered the most promising near-term solution for CO₂ capture from flue gas, yet the underlying reaction mechanisms are still not fully understood. Moreover, its widespread implementation is hindered by the high cost associated with the parasitic energy consumption during solvent regeneration, along with degradation and corrosion problems. First-principles-based atomistic modeling can play a significant role in elucidating the complex physicochemical phenomena underlying CO₂ reaction-diffusion behavior in aqueous amine-based solvent, especially when direct experimental characterization at the atomic level may be difficult. An improved fundamental understanding of these reaction mechanisms and intermolecular interactions can be used to provide explanations for experimental observations and fundamental data, and improve kinetic and thermodynamic models for process optimization. Here, our recent theoretical works on the molecular mechanisms underlying CO₂ capture and solvent regeneration in aqueous amines are presented. Through systematic comparative analyses of primary, tertiary, and sterically hindered amines, and diamines, we provide significant insights into how the mechanisms and rates of competing CO₂ absorption routes can be influenced by the solvent structure, the relative strengths of intra- and intermolecular hydrogen bond interactions, and steric constraints. We also use a theoretical approach to examine the mechanisms occurring during thermal degradation, as well as the process underlying leaching of metal ions into solution due to corrosion and subsequent oxidative degradation, which remain unclear. These studies further demonstrate the importance of a detailed atomic-level description of the solution structure and dynamics to describe the reactions and in predicting the thermodynamic and kinetic properties in CO₂-loaded aqueous amines. Moreover, an accurate description of solvent composition near the gas interface and near the iron surface is critical in predicting the CO₂ capture and corrosion processes, respectively. This dissertation highlights the increasingly important role of first-principles-based computer simulations in the detailed mechanistic study of CO₂ capture by amine-based solvents, including solvent degradation and corrosion processes. The improved understanding gained from computational studies combined with experiment validations will greatly aid in the design and development of new solvents and inhibitors in efforts to improve the efficiency of commercial-scale applicationsItem Thermal degradation of PZ-promoted tertiary amines for CO2 capture(2015-05) Namjoshi, Omkar Ashok; Rochelle, Gary T.; Contreras, Lydia M; Cullinane, John T; Reible, Danny D; Willson, Carlton GThe thermal degradation of piperazine (PZ)-promoted tertiary amine solvents for CO2-capture has been investigated and quantified in this study, which takes place in the high temperature (>100 °C) section of the capture plant. PZ-promoted tertiary amine solvents possess comparable energy performance to concentrated PZ, considered a benchmark solvent for CO2 capture from flue gas without its solid solubility limits that hinder operational performance. PZ-promoted aliphatic tertiary amine solvents with at least one methyl group, such as methyldiethanolamine (MDEA), were found to be the least stable solvents and can be regenerated in the desorber between 120 and 130 °C. PZ-promoted tertiary amine solvents with no methyl groups, such as ethyldiethanolamine (EDEA), were found to have an intermediate stability and can be regenerated in the desorber between 130 and 140 °C. PZ-promoted tertiary morpholines, such as hydroxyethylmorpholine (HEM), were found to be stable above 150 °C. Tertiary amines with at least one hydroxyethyl or hydroxyisopropyl functional group form intermediate byproducts that can accelerate the degradation rate of the promoter by a factor from 1.5 to 2.3. Tertiary amines with 3-carbon and 5-carbon functional groups, such as dimethylaminopropanol or dimethylaminoethoxyethanol, form stable intermediate byproducts that do not readily react with the promoter. A degradation model for PZ-promoted MDEA that can be used for process design calculations using acidified solvent degradation to model the initial degradation rate over a range of CO2 loading and initial amine concentration was developed. Thermal degradation was modeled using second-order kinetics as a function of free amine and protonated amine. The degradation kinetics, along with the observed degradation products, suggest that the dominant pathway is by free PZ attack on a methyl substituent group of protonated MDEA to form diethanolamine (DEA) and 1-methylpiperazine (1-MPZ). The model predicts total amine loss from experimental CO2 degradation rate measurements within 20%. The modeling work was extended to other PZ-promoted tertiary amine solvents with bulkier substituent groups. PZ attack on ethyl or hydroxyethyl groups was 17% and 4% as fast, respectively, as attack on methyl groups.Item Understanding the plume dynamics and risk associated with CO₂ injection in deep saline aquifers(2011-05) Gupta, Abhishek Kumar; Bryant, Steven L.; Rochelle, Gary T.Geological sequestration of CO₂ in deep saline reservoirs is one of the ways to reduce its continuous emission into the atmosphere to mitigate the greenhouse effect. The effectiveness of any CO₂ sequestration operation depends on pore volume and the sequestration efficiency of the reservoir. Sequestration efficiency is defined here as the maximum storage with minimum risk of leakage to the overlying formations or to the surface. This can be characterized using three risk parameters i) the time the plume takes to reach the top seal; ii) maximum lateral extent of the plume and iii) the percentage of mobile CO₂ present at any time. The selection among prospective saline reservoirs can be expedited by developing some semi-analytical correlations for these risk parameters which can be used in place of reservoir simulation study for each and every saline reservoir. Such correlations can reduce the cost and time for commissioning a geological site for CO₂ sequestration. To develop such correlations, a database has been created from a large number of compositional reservoir simulations for different elementary reservoir parameters including porosity, permeability, permeability anisotropy, reservoir depth, thickness, dip, perforation interval and constant pressure far boundary condition. This database is used to formulate different correlations that relate the sequestration efficiency to reservoir properties and operating conditions. The various elementary reservoir parameters are grouped together to generate different variants of gravity number used in the correlations. We update a previously reported correlation for time to hit the top seal and develop new correlations for other two parameters using the newly created database. A correlation for percentage of trapped CO₂ is also developed using a previously created similar database. We find that normalizing all risk parameters with their respective characteristic values yields reasonable correlations with different variants of gravity number. All correlations confirm the physics behind plume movement in a reservoir. The correlations reproduce almost all simulation results within a factor of two, and this is adequate for rapid ranking or screening of prospective storage reservoirs. CO₂ injection in saline reservoirs on the scale of tens of millions of tonnes may result in fracturing, fault activation and leakage of brine along conductive pathways. Critical contour of overpressure (CoP) is a convenient proxy to determine the risk associated with pressure buildup at different location and time in the reservoir. The location of this contour varies depending on the target aquifer properties (porosity, permeability etc.) and the geology (presence and conductivity of faults). The CoP location also depends on relative permeability, and we extend the three-region injection model to derive analytical expressions for a specific CoP as a function of time. We consider two boundary conditions at the aquifer drainage radius, constant pressure or an infinite aquifer. The model provides a quick tool for estimating pressure profiles. Such tools are valuable for screening and ranking sequestration targets. Relative permeability curves measured on samples from seven potential storage formations are used to illustrate the effect on the CoPs. In the case of a constant pressure boundary and constant rate injection scenario, the CoP for small overpressures is time-invariant and independent of relative permeability. Depending on the relative values of overall mobilities of two-phase region and of brine region, the risk due to a critical CoP which lies in the two-phase region can either increase or decrease with time. In contrast, the risk due to a CoP in the drying region always decreases with time. The assumption of constant pressure boundaries is optimistic in the sense that CoPs extend the least distance from the injection well. We extend the analytical model to infinite-acting aquifers to get a more widely applicable estimate of risk. An analytical expression for pressure profile is developed by adapting water influx models from traditional reservoir engineering to the "three-region" saturation distribution. For infinite-acting boundary condition, the CoP trends depend on same factors as in the constant pressure case, and also depend upon the rate of change of aquifer boundary pressure with time. Commercial reservoir simulators are used to verify the analytical model for the constant pressure boundary condition. The CoP trends from the analytical solution and simulation results show a good match. To achieve safe and secure CO₂ storage in underground reservoirs several state and national government agencies are working to develop regulatory frameworks to estimate various risks associated with CO₂ injection in saline aquifers. Certification Framework (CF), developed by Oldenburg et al (2007) is a similar kind of regulatory approach to certify the safety and effectiveness of geologic carbon sequestration sites. CF is a simple risk assessment approach for evaluating CO₂ and brine leakage risk associated only with subsurface processes and excludes compression, transportation, and injection-well leakage risk. Certification framework is applied to several reservoirs in different geologic settings. These include In Salah CO₂ storage project Krechba, Algeria, Aquistore CO₂ storage project Saskatchewan, Canada and WESTCARB CO₂ storage project, Solano County, California. Compositional reservoir simulations in CMG-GEM are performed for CO₂ injection in each storage reservoir to predict pressure build up risk and CO₂ leakage risk. CO₂ leakage risk is also estimated using the catalog of pre-computed reservoir simulation results. Post combustion CO₂ capture is required to restrict the continuous increase of carbon content in the atmosphere. Coal fired electricity generating stations are the dominant players contributing to the continuous emissions of CO₂ into the atmosphere. U.S. government has planned to install post combustion CO₂ capture facility in many coal fired power plants including W.A. Parish electricity generating station in south Texas. Installing a CO₂ capture facility in a coal fired power plant increases the capital cost of installation and operating cost to regenerate the turbine solvent (steam or natural gas) to maintain the stripper power requirement. If a coal-fired power plant with CO₂ capture is situated over a viable source for geothermal heat, it may be desirable to use this heat source in the stripper. Geothermal brine can be used to replace steam or natural gas which in turn reduces the operating cost of the CO₂ capture facility. High temperature brine can be produced from the underground geothermal brine reservoir and can be injected back to the reservoir after the heat from the hot brine is extracted. This will maintain the reservoir pressure and provide a long-term supply of hot brine to the stripper. Simulations were performed to supply CO₂ capture facility equivalent to 60 MWe electric unit to capture 90% of the incoming CO₂ in WA Parish electricity generating station. A reservoir simulation study in CMG-GEM is performed to evaluate the feasibility to recycle the required geothermal brine for 30 years time. This pilot study is scaled up to 15 times of the original capacity to generate 900 MWe stripping system to capture CO₂ at surface.Item Using analytical and numerical modeling to assess deep groundwater monitoring parameters at carbon capture, utilization, and storage sites(2013-12) Porse, Sean Laurids; Young, Michael H.Carbon Dioxide (CO₂) Enhanced Oil Recovery (EOR) is becoming an important bridge to commercialize geologic sequestration (GS) in order to help reduce anthropogenic CO₂ emissions. Current U.S. environmental regulations require operators to monitor operational and groundwater aquifer changes within permitted bounds, depending on the injection activity type. We view one goal of monitoring as maximizing the chances of detecting adverse fluid migration signals into overlying aquifers. To maximize these chances, it is important to: (1) understand the limitations of monitoring pressure versus geochemistry in deep aquifers (i.e., >450 m) using analytical and numerical models, (2) conduct sensitivity analyses of specific model parameters to support monitoring design conclusions, and (3) compare the breakthrough time (in years) for pressure and geochemistry signals. Pressure response was assessed using an analytical model, derived from Darcy's law, which solves for diffusivity in radial coordinates and the fluid migration rate. Aqueous geochemistry response was assessed using the numerical, single-phase, reactive solute transport program PHAST that solves the advection-reaction-dispersion equation for 2-D transport. The conceptual modeling domain for both approaches included a fault that allows vertical fluid migration and one monitoring well, completed through a series of alternating confining units and distinct (brine) aquifers overlying a depleted oil reservoir, as observed in the Texas Gulf Coast, USA. Physical and operational data, including lithology, formation hydraulic parameters, and water chemistry obtained from field samples were used as input data. Uncertainty evaluation was conducted with a Monte Carlo approach by sampling the fault width (normal distribution) via Latin Hypercube and the hydraulic conductivity of each formation from a beta distribution of field data. Each model ran for 100 realizations over a 100 year modeling period. Monitoring well location was varied spatially and vertically with respect to the fault to assess arrival times of pressure signals and changes in geochemical parameters. Results indicate that the pressure-based, subsurface monitoring system provided higher probabilities of fluid migration detection in all candidate monitoring formations, especially those closest (i.e., 1300 m depth) to the possible fluid migration source. For aqueous geochemistry monitoring, formations with higher permeabilities (i.e., greater than 4 x 10⁻¹³ m²) provided better spatial distributions of chemical changes, but these changes never preceded pressure signal breakthrough, and in some cases were delayed by decades when compared to pressure. Differences in signal breakthrough indicate that pressure monitoring is a better choice for early migration signal detection. However, both pressure and geochemical parameters should be considered as part of an integrated monitoring program on a site-specific basis, depending on regulatory requirements for longer term (i.e., >50 years) monitoring. By assessing the probability of fluid migration detection using these monitoring techniques at this field site, it may be possible to extrapolate the results (or observations) to other CCUS fields with different geological environments.