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«Carbon Dioxide Capture by Chemical Absorption: A Solvent Comparison Study by Anusha Kothandaraman B. Chem. Eng. Institute of Chemical Technology, ...»

-- [ Page 1 ] --

Carbon Dioxide Capture by Chemical Absorption:

A Solvent Comparison Study

by

Anusha Kothandaraman

B. Chem. Eng.

Institute of Chemical Technology, University of Mumbai, 2005

M.S. Chemical Engineering Practice

Massachusetts Institute of Technology, 2006

SUBMITTED TO THE DEPARTMENT OF CHEMICAL ENGINEERING

IN PARTIAL FULFILLMENT OF THE REQUIREMENTS FOR THE DEGREE OF

DOCTOR OF PHILOSOPHY IN CHEMICAL ENGINEERING PRACTICE

AT THE

MASSACHUSETTS INSTITUTE OF TECHNOLOGY

JUNE 2010 © 2010 Massachusetts Institute of Technology All rights reserved.

Signature of Author……………………………………………………………………………………… Department of Chemical Engineering May 20, 2010 Certified by……………………………………………………….………………………………… Gregory J. McRae Hoyt C. Hottel Professor of Chemical Engineering Thesis Supervisor Accepted by………………………………………………………………………………

William M. Deen Carbon P. Dubbs Professor of Chemical Engineering Chairman, Committee for Graduate Students

Carbon Dioxide Capture by Chemical Absorption:

A Solvent Comparison Study by Anusha Kothandaraman Submitted to the Department of Chemical Engineering on May 20, 2010 in partial fulfillment of the requirements of the Degree of Doctor of Philosophy in Chemical Engineering Practice Abstract In the light of increasing fears about climate change, greenhouse gas mitigation technologies have assumed growing importance. In the United States, energy related CO2 emissions accounted for 98% of the total emissions in 2007 with electricity generation accounting for 40% of the total1. Carbon capture and sequestration (CCS) is one of the options that can enable the utilization of fossil fuels with lower CO2 emissions. Of the different technologies for CO2 capture, capture of CO2 by chemical absorption is the technology that is closest to commercialization. While a number of different solvents for use in chemical absorption of CO2 have been proposed, a systematic comparison of performance of different solvents has not been performed and claims on the performance of different solvents vary widely. This thesis focuses on developing a consistent framework for an objective comparison of the performance of different solvents. This framework has been applied to evaluate the performance of three different solvents – monoethanolamine, potassium carbonate and chilled ammonia.

In this thesis, comprehensive flowsheet models have been built for each of the solvent systems, using ASPEN Plus as the modeling tool. In order to ensure an objective and consistent comparison of the performance of different solvent systems, the representation of physical properties, thermodynamics and kinetics had to be verified and corrected as required in ASPEN Plus. The ASPEN RateSep module was used to facilitate the computation of mass transfer characteristics of the system for sizing calculations. For each solvent system, many parametric simulations were performed to identify the effect on energy consumption in the system. The overall energy consumption in the CO2 capture and compression system was calculated and an evaluation of the required equipment size for critical equipment in the system was performed. The degradation characteristics and environmental impact of the solvents were also investigated. In addition, different flowsheet configurations were explored to optimize the energy recuperation for each system.

Monoethanolamine (MEA) was evaluated as the base case system in this thesis.

Simulations showed the energy penalty for CO2 capture from flue gas from coal-fired power plants to be 0.01572 kWh/gmol CO2. The energy penalty from CO2 regeneration accounted for 60% of the energy penalty while the compression work accounted for 30%.

The process flexibility in the MEA system was limited by degradation reactions. It was found that different flowsheet configurations for energy recuperation in the MEA system did not improve energy efficiency significantly.

Chilled ammonia was explored as an alternative to MEA for use in new coal-fired power plants as well as for retrofitting existing power plants. The overall energy penalty for CO2 capture in chilled ammonia was found to be higher than in the MEA system, though energy requirements for CO2 regeneration were found to be lower. The energy penalty for 85% capture of CO2 in the chilled ammonia system was estimated to be 0.021 kWh/gmol CO2. As compared to the MEA system, the breakdown of the energy requirements was different with refrigeration in the absorber accounting for 44% of the energy penalty.

This illustrates the need to perform a systemwide comparison of different solvents in order to evaluate the performance of various solvent systems.

The use of potassium carbonate as a solvent for CO2 capture was evaluated for use in Integrated Reforming Combined Cycle (IRCC) system. With potassium carbonate, a high partial pressure of CO2 in the flue gas is required. Different schemes for energy recuperation in the system were investigated and the energy consumption was reduced by 22% over the base case. An optimized version of the potassium carbonate flowsheet was developed for an IRCC application with a reboiler duty of 1980 kJ/kg.





In conclusion, a framework for the comparison of the performance of different solvents for CO2 capture has been developed and the performance of monoethanolamine, chilled ammonia and potassium carbonate has been compared. From the standpoint of energy consumption, for existing power plants the use of MEA is found to be the best choice while for future design of power plants, potassium carbonate appears to be an attractive alternative. An economic analysis based on the technical findings in this thesis will help in identifying the optimal choices for various large, stationary sources of CO2.

Thesis Supervisor: Gregory J. McRae Title: Hoyt C. Hottel Professor of Chemical Engineering 1: Energy Information Administration, Electric Power Annual 2007: A Summary. 2009: Washington D.C.

–  –  –

I would like to begin by sincerely thanking my advisor, Prof. Greg McRae for his constant support, guidance and mentorship over the course of this thesis. He gave me the freedom to define my thesis statement and always acted as a very helpful sounding board for my ideas. Whenever I was bereft of ideas, my discussions with him and his insights always helped me get back on the right track. He has always encouraged me to explore a wide variety of opportunities. I have truly learnt a lot from him over the past 5 years and for this, I am very grateful.

I would also like to thank my thesis committee members – Howard Herzog, Prof.

William Green and Prof. Ahmed Ghoniem for their valuable suggestions and advice. My collaborators at NTNU – Prof. Olav Bolland and Lars Nord were always ready to help me in understanding the power cycles and power plant modeling and I thank them for their time and helpful discussions. I am also very thankful to Randy Field for all his help with the ASPEN modeling in this work.

I am very grateful to the Norwegian Research Council, StatoilHyrdo, the Henry Bromfield Rogers Fellowship at MIT and the BPCL scholarship for the funding they have provided that has aided me greatly in the completion of this work.

Past and present members of the McRae group have been great sources of cheer and comfort during the past 5 years and I am grateful to them for their support. I would like to thank Ingrid Berkelmans, Bo Gong, Alex Lewis, Mihai Anton, Ken Hu, Carolyn Seto, Adekunle Adeyemo, Arman Haidari, Chuang-Chung Lee, Sara Passone, Jeremy Johnson and Patrick deMan for their friendship over the years. I would also like to thank Joan Chisholm, Liz Webb and Mary Gallagher for their support over the years and for making my life at MIT so much easier.

On a personal note, I know that this work could not have been completed without the tremendous support of my friends and family. I would like to thank my friends at MIT for all the good memories they have provided over the past few years. Ravi has been a great source of strength and support for me through each step of the journey and I thank him for his constant encouragement, optimism and belief in me. Finally, my gratitude to my parents is beyond measure – all through my life, they have always sacrificed to ensure that I had the best opportunities possible and they have constantly believed in me and encouraged me to dream big and to pursue those dreams. I cannot put into words what their support has meant to me over the years and I dedicate this thesis to them.

–  –  –

CHAPTER 1: INTRODUCTION

1.1 Motivation for carbon capture and sequestration

1.2 Brief overview of CO2 capture systems

1.2.1 Post-combustion capture

1.2.2 Oxyfuel combustion

1.2.3 Chemical looping combustion

1.2.4 Precombustion capture

1.3 Current status of CO2 capture technology

1.4 Solvent systems for chemical absorption

1.5 Thesis objectives

1.6 Thesis Overview

1.7 References

CHAPTER 2: ASPEN THERMODYNAMIC AND RATE MODELS

2.1 Electrolyte NRTL model

2.1.1 Long range contribution

2.1.2 Born expression

2.1.3 Local contribution

2.2 Soave-Reidlich-Kwong equation of state

2.3 Reidlich-Kwong-Soave-Boston-Mathias equation of state

2.4 Rate-based modeling with ASPEN RateSep

2.4.1 Flow models

2.4.2 Film reactions

2.4.3 Column hydrodynamics

2.5 Aspen Simulation Workbook

2.6 References

CHAPTER 3: MONOETHANOLAMINE SYSTEM

3.1 Process description

3.2 Chemistry of the MEA system

3.2.1 Carbamate formation in the MEA system

3.3 Thermochemistry in the MEA system

3.4 VLE in the MEA-CO2-H2O system

3.5 Degradation of MEA solvent

3.5.1 Carbamate polymerization

3.5.2 Oxidative degradation

3.6 MEA flowsheet development

3.7 MEA system equilibrium simulation results

3.8 Rate-based modeling of the MEA system

3.8.1 Film discretization

3.8.2 Sizing of equipment

3.9 Results from rate-based simulations for the MEA system

3.9.1 Effect of capture percentage

3.9.2 Effect of packing

3.9.3 Effect of absorber height

3.9.4 Effect of solvent temperature

3.9.5 Effect of desorber height

3.9.6 Effect of desorber pressure

3.9.7 Breakdown of energy requirement in the reboiler

3.9.8 Effect of cross-heat exchanger

3.9.9 Other methods of energy recuperation

3.10 Calculation of work for the MEA system

3.11 Total work for CO2 capture and compression for NGCC plants................. 109 3.12 Total work for CO2 capture and compression in coal-fired power plants.. 110 3.13 MEA conclusion

3.14 References

CHAPTER 4: POTASSIUM CARBONATE SYSTEM

4.1 Process description

4.2 Chemistry of the potassium carbonate system

4.3 Vapor-liquid equilibrium in K2CO3-H2O-CO2 system

4.4 Difference in mode of operation between MEA and K2CO3 systems........... 125

4.5 Flowsheet development for potassium carbonate system

4.5.1 Effect of absorber pressure

4.6 Equilibrium results with 40 wt. % eq.K2CO3

4.7 Rate-based modeling of the potassium carbonate system

4.7.1 Film discretization

4.7.2 Definition of parameters used in the rate-based simulation

4.8 Results from rate-based simulation of the potassium carbonate system..... 132 4.8.1 Effect of packing

4.8.2 Effect of desorber height

4.8.3 Effect of desorber pressure

4.9 Energy recuperation in the K2CO3 system

4.9.1 Flashing of rich solution and heat exchange with lean solution................. 136 4.9.2 Use of split-flow absorber

4.10 Development of potassium carbonate model for Integrated Reforming Combined Cycle Plant

4.11 Use of potassium carbonate solvent with additives

4.12 Potassium carbonate system conclusion

4.13 References

CHAPTER 5: CHILLED AMMONIA SYSTEM

5.1 Chemistry of the chilled ammonia system

5.2 Thermodynamics of the chilled ammonia system



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