Declaration of authorship

POST-COMBUSTION CARBON CAPTURETECHNOLOGY IN COAL POWER PLANTS USINGMEA: CASE STUDY LONGANNET COAL POWERSTATION.BY

OKONKWO ALPHONSUS EMEKA

TOTHE NIGERIAN SOCIETY OF ENGINEERSIN PARTIAL FULFILLMENT OF THE REQUIREMENTFOR CORPORATE MEMBERSHIP

SEPTEMBER, 2013

ATTESTATION

I certify that the work in this report was carried by Okonkwo Alphonsus Emeka of Gas Division, Department of Petroleum Resources (DPR), Warri, Delta State.Name of SupervisorMembership No: Signature:.... Date: ACKNOWLEDGEMENT

My profound gratitude to God Almighty through whom all things are made possible. I wish to thank Engr. Elvis Duruji, Engr. Idiata, Engr M.T.H Williams whose guidance, corrections and constructive criticism helped to set the right frame for the knowledge expressed in this work. My sincere gratitude goes to my beloved mother, Mrs. Winifred Okonkwo, who has given me tremendous encouragement and support to become a registered Engineer.

Finally, I wish to thank everyone who has touched my life positively in one way or the other, in the course of this work and professional life, for want of space, it may not be possible to mention all your names here but I do sincerely appreciate and love you all. TABLE OF CONTENTS Page

ATTESTATION.........II

ACKNOWLEDGEMENT ........III

TABLE OF CONTENT........IVLIST OF FIGURES AND TABLES......VILIST OF ABBREVIATION.......VIIABSTRACT.........VIIICHAPTER ONE INTRODUCTION......1 1.1 BACKGROUND........1 1.2 OBJECTIVES........1 1.3 SIGNIFICANCE OF THE STUDY.....1

CHAPTER TWO LITERATURE REVIEW.....2 2.1 WHAT IS CARBON CAPTURE? .....2 2.2 SEPARATION AND CAPTURE OF CO2....2 2.2.1 Chemical Absorption.......4 2.2.2 Physical Absorption.......4 2.2.3 Pressure/Temperature Swing Adsorption....5 2.2.4 Cryogenic Separation.......5 2.2.5 Membrane Separation.......6 2.2.6 Biomimetic Approach.......6 2.2.7 Chemical Looping Combustion......6 2.3 THE CO2 CAPTURE TECHNOLOGIES/APPROACHES..9 2.3.1 Post-combustion Capture Technology.....9 2.3.1.1 Advantages of Post-Combustion Capture Technology.10 2.3.1.2 Limitations of Post-Combustion Capture Technology.11 2.3.2 Pre-combustion Capture Technology....12 2.3.3 Oxy-fuel Combustion Capture Technology...12 2.4 CO2 TRANSPORTATION.....14 2.4.1 Pipeline Transportation......15 2.4.2 Ship, Road and Rail Transportation....15 2.5 CO2 STORAGE.......16 2.5.1 Geological CO2 Storage......16CHAPTER THREEPROCESS DESCRIPTION....17 3.1 PULVERISED COAL (PC) POWER PLANT....17 3.2 POST-COMBUSTION CAPTURE TECHNOLOGY IN PC POWER PLANT (MEA BASED)

.....17CHAPTER FOUR DISCUSSION AND RECOMMENDATIONS..21CHAPTER FIVE CONCLUSION......24REFERENCES.........25APPENDIX..........27 LIST OF FIGURES AND TABLES

Figure Description Page

2.1 Technology options for CO2 separation .32.2 The three major CO2 capture technologies ..133.1 Post combustion capture- solvent scrubbing (Current Status) ....................................................193.2 Graphical representation of CO2 avoided ...20Table Description Page

2.1 Comparison of technology options for

CO2 separation .....72.2 Advantages and disadvantages of different CO2

capture technologies 134.1 Summary for main recommendations ...22

LIST OF ABBREVATIONS

CCS Carbon capture and Storage

CO2 Carbon dioxide

COE Cost of Electricity

DEA Diethanolamine

EOR Enhanced Oil Recovery

FGD Flue Gas Desulphurization

GHG Greenhouse Gases

H2 Hydrogen gas

IGCC Integrated Gas Combined Cycle

MEA Monoethanolamine

NOx Nitrogen OxidePC Pulverised Coal

SCR Selective Catalytic Reduction

SOx Sulphur Oxide

O2 OxygenABSTRACT

This work presented a comprehensive overview of post-combustion capture technologies with respect to Longannet power station in Scotland, United Kingdom, with a generating capacity of 2300MW. It analysed the operations of the post-combustion capture facility and also assessed the CO2 emissions from the Longannet carbon capture facility, pointing out the amount of CO2 captured, the amount of CO2 avoided and the amount CO2 emitted, as against a reference plant without a capture facility. The study also identified the major challenges facing the use of amines in post-combustion carbon capture technology and provided promising technologies with great potentials to overcome these challenges.

CHAPTER ONEINTRODUCTION

1.1 BackgroundCarbon capture and storage (CCS) is a technology consisting of the separation of CO2 from industrial and power plants, transport to a storage site and long-term isolation from the atmosphere. The emission of CO2 occurs when fossil fuels are used in power generation, transportation, domestic heating, cooking and other industrial purposes. The capture of CO2 became necessary against the backdrop of rising trends in average atmospheric temperature, which has been linked to the rising concentration of CO2 in the atmosphere, with its atmospheric concentration of 387ppm closing in on the stabilisation level of 450ppm. Power generation stations are the greatest sources of CO2 emission into the atmosphere and are good targets for the application of this CO2 capture technology. This project will hence give a brief and concise summary of the operations of post-combustion carbon capture facility at Longannet power station. 1.2 Objectives

The aim of this study is to critically assess post-combustion capture technology, using the facility at Longannet coal power station in Scotland as a case study. 1.3 Significance of the Study.

The study evaluates the post-combustion carbon capture approach in a pulverised coal power plant and assesses the amount of CO2 captured, CO2 avoided and CO2 emitted from the 2300MW power plant with post-combustion capture facility, as against a reference plant without a capture facility.

It examines the present challenges facing the development of post-combustion technology and tries to identify ways of improving its overall efficiency through minimisation of energy requirement with respect to pulverised coal power plant.CHAPTER TWO

LITERATURE REVIEW

2.1 What is Carbon Capture?

CCS is a well integrated system with three basic stages namely; capture from a source, transport and storage. CO2 Capture refers to the sequestration of carbon in form of CO2 from the other components in the flue gas or process stream of a power plant or an industrial facility. CO2 capture is a large process and is best adapted to large point sources of CO2 such as power stations, large industrial plants and refineries. Dooley et al. (2006) defined a complete end-to-end carbon capture and storage (CCS) system as a dedicated assemblage of various technologies and components many of which are already used in other settings, working together to prevent CO2 from entering the atmosphere. Given the high level of reliance on fossil fuels to meet the energy demands as was seen from the previous chapter, capturing CO2 will be a radical departure from conventional thinking about climate mitigation which would require eliminating or strictly limiting the use of fossil fuels. Hence this makes the process an attractive option as fossil fuels will continue to be used without contributing immensely to greenhouse warming. Yang et al. (2008) stated that the three major options to reduce total CO2 emission are to reduce energy intensity, carbon intensity and develop CCS. CCS is capable of removing about 48GtCO2, which is about 19% total emission reduction in atmosphere needed by the year 2050 to stabilize the climate, if it is able to overcome the problem of cost (IEA GHG, 2007).

2.2 Separation and Capture of CO2

The practice of separating CO2 from flue gas streams started in the 1970s not with concern about the climate change and global warming, but as a potentially economic source of CO2 mainly for food industry and enhanced oil recovery (EOR) operations. The different separation methods can be retrofitted to existing power generation plants or incorporated in the design of new plants. Generally most of these technologies involve

Solvent wet scrubbing with a chemical or physical absorbent.

Solid dry scrubbing with a physical or chemical adsorbent.

Cryogenic separation methods

Membrane separation.

Enzymatic/Algae separation.

The choice of an appropriate technology depends on the properties of the flue gas stream from which CO2 needs to be separated which in turn depends on the power plant technology. Yang et al. (2008) noted that other factors like the CO2 recovery, capital and operating costs, environmental impact, the partial pressure of CO2 and sensitivity of the technology to other impurities and trace elements. Some of these separation methods will be discussed briefly below.

Figure 2.1: Technology option for CO2 separation (Olajire, 2010)

2.2.1 Chemical Absorption

Absorption systems separate CO2 from the flue gas resulting from the combustion of fossil fuel in air. These systems separate a component from a flue gas stream by reacting with it. Chemical absorption refers to the process by which the CO2 is absorbed into a solvent by the formation of a chemically bonded compound. The fraction of CO2 scrubbed in this process is between 12-15 vol/vol % from coal and 4 -8% for gas fired plants (IPCC, 2005). In order to obtain a gas stream rich in CO2, the CO2 laden solvent is passed through a regeneration unit. Upon heating the product, the bond between the absorbent and CO2 will be broken, yielding a stream enriched in CO2. Amines are commonly used as solvents for chemical absorption processes. Those with commercial interest for gas purification include monoethanolamine (MEA), diathanolamine (DEA), and methydiethanolamine (MDEA) but for the purpose of this work, monoethanolamine (MEA) will considered as a reference case, especially as it regards to post-combustion technology. There are other solvents like ammonia, amino acid salts and potassium carbonate which have been gaining attention recently due to their advantages over MEA, but these solvents will be discussed in subsequent chapters.

2.2.2 Physical Absorption

The use of inorganic or organic liquids to preferentially absorb a gaseous component from a mixture is known as physical absorption. The absorption liquid is produced by increasing the temperature of the absorbent or reducing its pressure, with the overall process performance depending on operating temperature, pressure, gas composition and absorption liquid. High pressure conditions favour the use of this separation method, and hence a very efficient technique for processing such high-pressure CO2 gas stream encountered in integrated gasification combined cycle plants (Steeneveldt et al, 2006). Kanniche et al. (2009) noted that physical solvents are more suitable for CO2 partial pressure greater than 8 bars, while chemical solvents (for chemical absorption) are for CO2 partial pressure less than 8 bars. Physical absorption is mostly applied at commercial scale where CO2 high concentration is involved unlike the chemical absorption which is used for low CO2 concentration. Examples of physical solvents are dimethylether of polypropylene glycol, chilled methanol, propylene carbonate, and are used for Selexol, Rectisol and Fluor Carbonate physical absorption processes respectively. Other physical solvents are the ionic liquids, although it also finds its use recently in chemical absorption processes. These are salts which have melting temperature below the boiling point of water and have high gas absorption capacity. Ionic liquids will be discussed more in the next chapter.

2.2.3 Pressure/Temperature Swing Adsorption

The adsorption process is based on the same principle as absorption, but using porous solid adsorbents such as zeolites and activated carbon, and proceeds with or without chemical reaction between the adsorbent and CO2. The sorption and regeneration are accomplished by cyclic changes in the vessel where solids are contained, and not by circulation between vessels like in absorption separation. The driving force for the separation could either be temperature (temperature swing adsorption) or pressure (pressure swing adsorption).2.2.4 Cryogenic Separation

The separation of a gaseous mixture is achieved by the initiation of a phase change by cooling and condensing of the component that is to be separated, and finally removing it as either a liquid or solid. This approach utilises the benefit of different temperatures at which CO2 and other components of flue gas stream change from a liquid to gas or gas to liquid. Cryogenic separation is a low temperature operation and well suited for streams with high concentration of CO2 and reduces the use of chemicals, water consumption and corrosive issues. Kanniche et al. (2009) noted that cryogenic separation requires too much energy and is highly expensive when the amount of CO2 in the exhaust gases is very low and at atmospheric pressure.

2.2.5 Membrane Separation

The process for separating CO2 from the flue gases, using membrane/amine hybrids processes. The membrane separates the gas components by acting as a permeable or semi-permeable barrier through which one or more of the gases in the mixture of gases moves faster than the others. The pressure difference across the membrane is usually the driving force for the gas flow through the membrane. As a result of this, they are often applied in high pressure streams. Membranes like metallic, polymeric and ceramic are used in CO2 capture facilities and hybrid membranes are still under investigation. Membranes are made to be as thin as possible to ensure maximum permeation rates without compromising mechanical strength. Membrane separation have great potential to be more efficient and of lower capital cost than solvent-based systems. 2.2.6 Biomimetic Approach

These are biological systems that utilize the naturally occurring reactions of CO2 in living organisms. Microalgae are large group of photosynthetic, heterotrophic organisms which have a unique potential for cultivation as energy crops because they are capable of converting sunlight, water, CO2 to sugars. This offers great potentials as it would prevent the need for CO2 compression and sequestration (Herzog et al., 2009). 2.2.7 Chemical Looping Combustion Chemical looping is slightly similar to the oxy-combustion process in that, before combustion, oxygen is removed from air by reacting with metal particles in a fluidised bed to produce metal oxides (oxidation reaction). The captured oxygen, which will be in form of metal oxides, is then contacted with fuel to release produced CO2 and water vapour, and the metal (reduction reaction). The water vapour is then condensed, leaving pure CO2. TABLE 2.1: Comparison of technology options for co2 separation (Rao et al., 2004; Olajire, 2010)Technology OptionSystem

RequirementAdvantagesProblems/drawbacks

Chemical

AbsorptionAbsorber and stripper sections

Chemical sorbent (MEA, MDEA, Ammonia, Blended amines) Suitable for dilute CO2 streams (typical flue gas from power plant) Operates at ordinary temperature and pressure Commercially available, proven technology Heat of sorbent regeneration is very high

Significant sorbent loses; pre-processing may be required (e.g sulphur removal)

Physical

AbsorptionAbsorber and stripper sections

Physical sorbent (DEPG, Chilled methanol, Propylene carbonate) Suitable only for gas streams with high partial pressure of CO2 (typical syngas from gasification systems) Less energy required assuming that the gas to be processed is already at high pressure

Sorbents are less susceptible to impurities in the gas stream Requires high operating pressure

Works better only with gas streams having high CO2 content; so it is not suitable for flue gas processing

AdsorptionAdsorber bed(s) Commercially available gas separation process Low capacity and CO2 selectivity of available adsorbents

MembranesMembrane filter(s) Upcoming, promising technology with diverse applications

Space efficient

No regeneration is required

No waste streams Requires high operating pressures

Lower product purity; need for multiple stages/cycles

Preventing membrane wetting is a major challenge

CryogenicRefrigeration and distillation units Direct production of liquid CO2 Requires very large amount of energy for refrigeration (not suitable for dilute streams)

Chemical Looping

CombustionReactor beds Exhaust gas stream for air reactor is harmless

Avoids huge energy penalty; and thus less operational cost No large-scale demonstration has been performed.

Table 2.1 shows the advantages and challenges of the various separation technologies. These technology options are presently under intense research and development in the improvement of energy penalty for CO2 capture in power generating plants. The separation methods are applied to capture technologies in the power generation stations to produce the desired CO2 capture.

2.3 The CO2 Capture Technologies/Approaches

The focal point of mitigating global CO2 emissions from the use of fossil fuels used in power generation plants in the entire carbon capture and storage process is the CO2 separation and capture stage. The power generation technologies that are easily adapted to carbon capture technology are conventional pulverised coal combustion steam power plants (PC), natural gas combined cycle plants (NGCC) and the advanced power systems such as the integrated gasification combined cycles (IGCC) plants A typical power plant consists of a boiler (where the fuel is burned and the heat used to generate high pressure steam) and a turbine (that converts thermal energy to mechanical energy through its shaft) and a generator (which transforms the mechanical energy into electrical power). However, in the case of the gasification power plants without CO2 capture, fossil fuels are first gasified to produce a mixture of carbon monoxide (CO) and hydrogen (H2) which expands in a gas turbine to generate electricity. The three major types of carbon capture processes are:

2.3.1 Post-combustion Capture Technology: In this technology, CO2 is separated from flue gas after the combustion of the fossil fuel. It normally uses a solvent to capture CO2 from the exhaust gases of power and industrial plants. The solvent is regenerated after the process. The CO2 capture solvent can be physical or chemical but chemical solvents, known as amines are mostly used. Chemical solvents are used because they are less dependent on partial pressure than physical solvents, therefore favouring the partial pressure of CO2 in the flue gas, which is low, normally between 4 -14% by volume (IEA GHG, 2007). This technology is widely used to capture CO2 for use in food and beverage industry.2.3.1.1 Advantages of Post-Combustion Capture Technology (MEA-based)

The amine solvent is commercially available. Amine based post combustion capture of CO2 from coal plants has been established, and numerous installations around the world have substantial experience with this process. This makes them readily applicable in curbing CO2 emissions from coal power plants.

Easy to retrofit and flexible compared to other methods. Post combustion approach to CO2 capture is an end of pipe or curative method of addressing CO2 emission from power plants. In this way, it may not be necessary to carry out extensive process modifications of the host plant in order to accommodate the capture plant.

The operation is ordinary and has lower risk. Monoethanolamine is able to capture CO2 from flue gases at very low concentrations, and at a pressure close to atmospheric pressure. The temperature range for the regeneration of CO2 from the solvent is between 100 140oC, and hence the process can proceed at a fairly low temperature condition.

CO2 purity. The level of purity of the recovered CO2 from pulverized coal plants using the amine based post combustion process can be as high as 95% (Steeneveldt et al., 2006).

High separation capacity. Although the concentration of CO2 in flue gases from a coal fired plant is very small (between 12 15%), they are recovered easily from the flue gas as a result of high chemical reactivity of amines (MEA) with CO2. The absorbed CO2 is also easily recovered from the solvent by the application of moderate amount of heat.

Renewable energy technologies can be integrated with it, for example, inexpensive solar collectors can be used to provide the heat needed to separate CO2 from the solvent (CISRO, 2007). It is robust to changes in fuel quality. Ability to adopt technology improvements, providing pathway toward zero-emissions.

2.3.1.2 Limitations to Post-Combustion Capture Technology

High energy requirement for solvent regeneration. The carbamate formed from the absorption process requires substantial energy to break the bonds. Secondly, electricity is required to drive the blowers and relatively higher electricity is needed to compress the captured CO2 for transport to storage site. This consumption of electricity and heat form the main sources of energy penalty and lead to 20-30% loss of generation efficiency to capture 90% of CO2 (IEA GHG, 2008). A facility with capture has to be larger than that without capture to achieve the same energy output. The IPCC Special Report Carbon dioxide Capture and Storage (2005) calculated that capture of 90% CO2 using conventional technologies would result in an increased fuel consumption of 24-40% and 4-25% for PC and IGCC plants respectively, compared to similar plants without capture. High energy requirement for post-combustion capture technology is regarded as a major challenge for its large scale demonstration. The conventional Econamine FG process heat requirement is around 4.2GJ/tonne CO2. Currently a number of solvents are being investigated to ascertain the one that is best suited for the chemical absorption with minimal energy requirement. This will be discussed extensively in the next chapter.

Retrofit potentially requires steam turbines modification and requires a large space for its installation. This is not always possible as most coal power plants and factories are built in industrial area with limited space available. .

.

High cost associated with the process. Capture costs are typically affected by sorbent regeneration, heat requirement, sorbent concentration, sorbent loss and cost. The absorption process requires large equipment sizes because of low concentrations of CO2 and hence additional cost. Due to the additional cost of capture facility, there is associated increase in cost, around 32-40/tCO2 avoided, and a considerable 60% increase in cost of electricity (COE).

2.3.2 Pre-combustion Capture Technology: This technology involves the gasification of fuel firstly; to produce a gaseous mixture of carbon monoxide (CO) and hydrogen H2 (synthesis gas), the produced gas is further reacted with steam under the right conditions of temperature and pressure to produce a gas stream consisting of CO2 and hydrogen. The CO2 can then be captured while the hydrogen is expanded in a turbine for electricity generation. This approach has the advantage of being cheaper and has lower energy consumption for solvent regeneration than the conventional post-combustion capture approach.

2.3.3 Oxy-fuel Combustion Capture Technology: The last approach is the case where the power plant is fed with pure oxygen instead of air; the resulting flue gas will be a mixture of CO2 and steam depending on the hydrogen content of the fuel source. The steam is condensed and then CO2 eventually captured. The CO2 captured can be stored with less downstream processing as the nitrogen concentration in the flue gas is much lower than when air is used for firing. The oxygen used is often produced on-site in an air separation plant which forms the highest cost component in the process because of its high energy demand. Radgen et al, (2006) noted that the high energy demand for producing oxygen could be reduced by applying membrane-based processes for oxygen production. Oxy-fuel combustion has better combustion efficiency and lower emissions.

Figure 2.2: The three major CO2 capture technologies (IFP, 2009)

Table 2.2: Advantages and disadvantages of different CO2 capture technologies

CO2 Capture Technology Advantages Disadvantages

Post-combustion Applicable to the majority of existing coal-fired power plants

Retrofit technology option

Low technology risk

Flexible operation and ability to adopt technology improvements with ease Low CO2 partial pressure

Significantly higher performance or circulation volume required for high capture levels

CO2 produced at low pressure compared to sequestration requirements

High energy penalty for solvent regeneration

Loss of Solvent

Pre-combustion High CO2 partial pressure

Increased driving force for separation

More technologies available for separation

Potential for reduction in compression costs/loads

Low emissions Applicable mainly to new plants, as few gasification plants are currently in operation

Barriers to commercial application of gasification are common to pre-combustion capture

Poor availability

High cost of equipment

Extensive supporting systems requirements

Cooling of gas to capture CO2 Efficiency loss in water-shift reaction

Oxy-combustion Very high CO2 concentration in flue gas

Retrofit and repowering technology option

Very low emissions

Absence of nitrogen provides low volume of gases and so reduced size of the overall process Large cryogenic O2 production requirement may be cost prohibitive

Cooled CO2 recycle required to maintain temperatures within limits of combustor materials

Decreased process efficiency

Added auxiliary load

2.4 CO2 TransportationCO2 has to be transported from the capture point to the place where it will either be utilised or stored in a safe and secure way. CO2 can be transported in the liquid and gaseous phase. The common means of transportation are pipelines, roads and rail tanks. Some form of pre treatment may be required before transporting the captured CO2, as it may contain some impurities as water vapour, hydrogen sulphide (H2S), Nitrogen (N2), methane (CH4), oxygen (O2), mercury (Hg) and other hydrocarbon (WRI, 2008).

2.4.1 Pipeline Transportation

In transporting CO2 through pipelines, gaseous CO2 is first compressed to a pressure above 8Mpa in order to avoid a two-phase flow regime, and to increase the density, making it easier and less costly to transport (IPCC, 2005). This compression pressure may however vary in different cases, depending on the desired delivery conditions, the transportation length and the composition of the gas to be transported (Steeneveldt et al., 2006). One of the major issues in pipeline transportation is corrosion and the estimated rates at which it will occur strongly influences the choice of material of construction for the pipelines. Pipeline corrosion rates are largely influenced by the composition of the gas being transported, with the amount of water vapour present being an important factor in corrosion prevention. 2.4.2 Ship, Road and Rail Transportation

Another common method of moving CO2 is ship transportation. Specially designed ships as those used in the transportation of liquefied natural gas (LPG) are used. Steeneveldt et al. (2006) stated that ships have the advantage of allowing collection of concentrated CO2 from various sources at volumes below the critical size for pipeline transportation. Their use requires the installation of facilities for compression, loading and unloading, as well as intermediate storage at the different collection points. Transportation of CO2 by road and rail are feasible, but have low comparative advantage in large scale CO2 capture projects. They may best be adapted to very small capture operations.

2.5 CO2 Storage

The mitigation of global climate changes due to CO2 emission effectively ends with the permanent storage or industrial utilisation of the captured CO2. The quantity of carbon that will be captured may be too large to be utilised in industrial processes and hence a need for some alternative storage media. The chosen media must be able to retain the gas without the CO2 leaking into the atmosphere. In selecting the appropriate medium of storage, certain key criteria must be applied. Such criteria include (Herzog and Golomb, 2004): (a) storage period should be prolonged, preferably hundreds to thousands of years, (b) cost of storage, including the cost of transportation from the source to the storage site, should be minimised, (c) the risk of accidents should be eliminated, (d) the environmental impact should be minimal, and (e) the storage method should not violate any national or international regulations. The three basic storage options are geological, ocean and mineral storage.

2.5.1 Geological CO2 Storage

The two main routes for storing CO2 are to inject it into geologic formation or into the ocean. The potential geological storage modes for CO2 include: Depleted oil and gas reservoirs

Deep saline formations

Storage in association with CO2 Enhanced Oil recovery (EOR) Projects.

Coal bed formations (unminable coal seams)

CHAPTER THREE

PROCESS DESCRIPTION3.1 Pulverised Coal (PC) power plantThis study was done at Longannet Power station in Scotland. The pulverised coal power station has a generating capacity of 2300MW, comprising of four separate generating units. The pulverized coal power generation starts by crushing coal into a fine powder that is fed into a boiler, where it is burned to create heat. The combustion process takes place in excess air to ensure complete combustion. The heat was used to produce steam which drives one or more turbines to generate electricity. The flue gases leaving the combustion chamber in a plant without CO2 capture were emitted into the air. However, the combustion of some coal types yields a flue gas with high NOx and SOx content. These were removed by the flue gas desulphurization (FGD) systems for SOx and low burner technology or selective catalytic reduction (SCR) systems for NOx.3.2 Post Combustion Capture Technology in PC Power Plant (MEA-based)Amines (Alkanolamines) are a family of organic compounds that are derivatives of alkanols (OH functional group) and have amino group (NH2) attached to one of the carbon atoms. Amines are water-soluble organic compounds that contain reactive nitrogen atoms. The conventional amines with commercial interest for CO2 absorption process include monoethanolamine (MEA), diathanolamine (DEA), and methydiethanolamine (MDEA). Below is a diagram for conventional amines. Monoethanolamine (MEA) was used for the purpose of this study and would be used as a reference case. MEA is a primary amine, colourless, toxic and viscous liquid with an odour similar to that of ammonia.

The CO2 in the flue gas leaving the combustion chamber was scrubbed by means of a liquid solvent. A continuous scrubbing system is often required to separate CO2 from a flue gas stream. The system consists of two main elements; an absorber in which the CO2 was absorbed into a specific solvent, and a regenerator (or stripper) in which CO2 was released (mostly in concentrated form) and the original solvent recycled. The flue gas from the Longannet power plant was first cooled to 400C- 500C and passed through the absorber, with aqueous monoethanolamine solvent flowing through absorber in a counter current pattern. The absorber contains packing materials which provided contact surface area between the flue gas and the solvent. The absorption of CO2 occurred through a chemical reaction, resulting in the formation of a chemically bonded compound named MEA Carbamate. The treated gas was then vented into the atmosphere.The CO2 rich solvent leaving the absorption column was pumped into the regenerator or stripper. The absorbed CO2 was recovered in the stripper by breaking the bond between the CO2 and the amines (Carbamate). CO2 was recovered from the solvent at elevated temperatures (100 140oC) and a pressure slightly higher than the normal atmospheric pressure. The heat energy required to regenerate CO2 from monoethanolamine is drawn from the steam cycle of the host plant. After the CO2 has been stripped from the CO2 rich solvent, the lean solvent was recycled back into the absorption column to continue the cycle. Fresh MEA was also added to compensate for the losses incurred in the process. The recovered CO2 was dried and compressed, in readiness for storage. Generally, the process chemistry for the chemical absorption is complex but the major reactions were;

CO2 Absorption: 2R-NH2 + CO2 R-NH3+ + R-NH-COO

MEA Regeneration: R-NH-COO - + R-NH3+ + Heat CO2 + 2R-NH2

Figure 3.1: Post-combustion capture (solvent scrubbing)-current status Coal burns to release about 0.3kg CO2 per MJ electricity generated. Converting this to KWh (i.e multiplying by 3.6) gives about 1.08kg CO2 emitted per KWh generated. The Longannet coal-fired power station has a generation capacity of 2300 MW and therefore emits:-

= (2,300,000 x 24x 365)kwh/year

= (2,300,000 x 24 x 365 x1.08)kg CO2/year

= 21,759,840 tonnes of CO2/yearThe coal plant emitted 21.7Mega tonnes of CO2 per year before the installation of capture facility but emitted about 26.9 30.3Mega tonnes of CO2 after the installation of capture facility (as a result of additional fuel consumption between 24% - 40%) in order to generate the same energy output. Since the facility was designed to capture 90% of CO2, then about 24.2- 27.3 Mega tonnes of CO2 was captured, while 2.7- 3 Mega tonnes was emitted. The CO2 avoided now becomes the difference in emissions between the reference and capture plant, which is 18.7- 19 Mega tonnes. See appendix for calculations.

Figure 3.2: Graphical representation of CO2 avoided CHAPTER FOUR DISCUSSION AND RECOMMENDATIONS

Fossil fuels, especially coal has continued to play a dominant role in meeting global energy demand. The post-combustion technology helps to achieve a balance between meeting the energy demand, economic development and protecting the environment. For large Longannet coal power plant with a generating capacity of 2300MW, 18.7- 19 Mega tonnes of CO2 were avoided yearly, while 2.7 3 Mega tonnes were emitted into the atmosphere instead of 21.7 Mega tonnes (plant without a capture facility). Therefore the technology saves the environment of 18.7- 19 Mega tonnes of CO2 yearly from a single centralised source. Since coal is responsible for almost half (40%) of global CO2 emissions, installations, development and transfer of this technology is highly recommended.

The technology has some inherent challenges facing its global commercialisation especially in the use of amines to capture the CO2 gas, because of the required high thermal input for the recovery of the separated CO2 from the absorbing solvent medium. This study noted that process efficiency can be substantially improved by careful development of solvents that can overcome these inadequacies presented by MEA. Chilled ammonia, aqueous ammonia and carbonate-based (Na2CO3 and K2CO3/PZ) have shown great improvement over the conventional MEA in terms of tolerance to oxygen degradation and flue gas impurities, high absorption/desorption rates, low corrosion rate, higher stability and high absorption capacity. The ammonia process similar to MEA system but unlike the MEA process, ammonia does not have absorbent degradation and corrosion problems caused by SO2 and O2 in the flue gas, and offers potentials for regeneration at high pressure. Aqueous ammonia reacts with CO2 as a dissolved ammonia carbonate to form ammonia bicarbonate with much lower heat of reaction, compared to that of amine-based systems. Chilled ammonia and aqueous ammonia have great potentials but have ammonia slippage and slower absorption rate as drawbacks. The dominant reaction is the equilibrium reaction below; 2NH4HCO3 (NH4)2CO3 + CO2 + H2OFurther improvement can be achieved by process integration and process intensification. Integration of flue gas desulphurisation unit and capture plant into the coal power plant, the use of advanced supercritical boilers to achieve the best steam conditions, extraction of low pressure steam at the lowest possible temperature from the steam cycle and condensate heating with the recovered waste heat from the compressor would ensure much higher efficiency in both the capture and power plant. Process intensification with rotating packed beds, compact heat exchangers and heat enhancements would not only guarantee smaller component sizes, increased throughput, more efficient and safer process, but also a significant reduction in capital and operating cost which will invariably lead to cheaper cost of electricity (COE).

Table 4.1: Summary for main recommendations

Reduction of CO2 which is a greenhouse gas (GHG) can help mitigate global warming Coal delivers about 30% of worlds primary energy, 39% of worlds net electricity and responsible for over 40% of global CO2 emissions with current atmospheric concentration of 387ppm closing-in on stabilisation level of 450ppm. High energy requirement and cost have been identified as the most important barriers to commercialisation of post-combustion. These can be addressed by improvements in solvents, process simplification, process integration and intensification.

To ensure complete optimisation of the processes above, all aspects of the entire post-combustion technology should be energy efficient. Financial support from the government and industry is mandatory

Public awareness on capture technology and its role in global emissions reduction should be encouraged.

Diffusion and transfer of technologies to developing countries and their capacity to apply the technology should be mandatory. Establishment of an institution or forum that would encourage practical work on post-combustion capture technologies and identification of safe and large capacity storage site or CO2 usage facility is important. Creating a legal-regulatory framework by government. Learning-by-doing is imperative as this has yielded commendable improvements with similar technologies There should be seamless communication between the Chemical and Mechanical Engineers in developing new sorbents. More intensified effort should be geared towards the development of breakthrough technologies as they offer more potentials towards reductions in energy demand and cost Continued and intensified research is mandatory as post-combustion technology offers great potentials.

CHAPTER FIVE CONCLUSION

This work provided a comprehensive overview of post-combustion carbon capture technology, using the Longannet coal power station as a case study, with particular emphasis on ways of improving post-combustion capture technology. As coal will remain the dominant source of fuel of primary energy at least till 2050, because of its low cost and abundant reserves, especially in countries like China, United States, Russia, and the security and economics of its supply, capture technologies will thus, be mandatory to mitigate CO2 emissions from large coal power plants. Though switching to other sources of fuel/renewable energy source and improved energy efficiency may seem to be superior strategies, CO2 capture technologies are indispensable if CO2, which is a greenhouse gas is to be reduced from centralised sources. Post-combustion capture technologies from large centralised sources like power plants can be effectively accomplished through continued research to develop technologies and processes, development of technologies and project demonstrations. Public and government support are generally required to achieve this especially in terms of technical and financial incentives, as much further work is still needed to effectively commercialise this technology.

Post-combustion capture technology is presently the only available and most feasible technology to be implemented in near future particularly for existing and new coal power plants between now and 2020, but has a major limitation in terms of high energy requirement which directly affects cost. An optimised process (solvent improvement, intensification, simplification and integration, breakthrough technologies) and learning-by-doing will significantly reduce the energy demand and cost and hence, position post-combustion capture technology in an actively competitive level with other low carbon technologies.

Post-combustion capture can be an important and timely part of the solution to climate change but is by itself insufficient, as many measures are necessary to create the required total cumulative emission reduction. REFERENCES

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APPENDIX

24% fuel increase=124% of 21.7 = 124/100 x 21.7= 26.9 Mega tonnes of CO240% fuel increase =140% of 21.7= 140/100 x 21.7 = 30.3 Mega tonnes of CO290% capture= 90/100 x26.9 = 24.2Mega tonnes of CO290% capture = 90/100 x 30.3 = 27.3 Mega tonnes of CO2CO2 emitted = 26.9 - 24.2= 2.7 Mega tonnes

CO2 emitted = 30.3 27.3= 3 Mega tonnes

CO2 avoided = 21.7 (without capture facility) 2.7= 19 Mega tonnes

CO2 avoided = 21.7(without capture facility) 3 = 18.7 Mega tonnesMitigation cost

This cost is expressed in per tonne of CO2 avoided, and is a useful way to compare different mitigation strategies. The cost of CO2 mitigation varies, depending on the capture plant and the base case power plant. For example, the analysis of different CO2 mitigation strategy for a PC plant will compare the cost of mitigation from post combustion and oxyfuel combustion methods, to the reference PC plant without capture.

Cost of CO2 avoided =

(/kWh) cap - (/kWh) ref

(tonnes CO2 emitted/kWh) ref - tonnes CO2 emitted/kWh) cap

cap = capture plant

ref = reference plant

/kWh = levelized COE

tonne CO2emitted/kWh = metric tonne of CO2 emitted by the plant per kWh net generation

In contrast, the cost per unit of CO2 removed or captured is simply the additional expense incurred in the capture of CO2, divided by the total quantity of CO2 captured

ii