Carbon Capture Technology A Technoeconomic Evaluation of Absorption, Gasification,

and Oxy-Coal Combustion for Coal Power Plants

Will Backus

12/17/2010

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Table of Contents

Executive Summary…………………………………………………………………………………………………………….. 2

Introduction………………………………………………………………………………………………………………………… 3

Sequestration……………………………………………………………………………………………………………………… 4

Absorption……………………….…………………………………………………………………………………………………. 5

Gasification………………………………………………………………………………………………………………………… 8

Oxy-Coal Combustion…………………………………………………………………………………………………………. 9

Case Study Outline..……………………………………………………………………………………………………………. 11

Analysis……………………………………………………………………………………………………………………………… 12

Energy Efficiency……………………………………………………………………………………………………….. 12

Cost of Electricity………………………………………………………………………………………………………. 13

Environmental Impact...……………………………………………………………………………………………. 14

Special Cases…………………………………………………………………………………………………………….. 15

Retro-Fitting……………………………………………………………………………………………………………… 17

Conclusion………………………………………………………………………………………………………………………… 17

References………………………………………………………………………………………………………………………… 20

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Executive Summary

This report examines three different methods of carbon dioxide (CO2) capture for carbon

capture and sequestration (CCS) systems for coal fired power plants. The purpose of this report is to

compare the three distinct technologies for overall feasibility of large scale implementation on standard

coal power plants.

Many political and economic reasons have forced industries, including the electric power sector,

to move towards adopting greener technologies as CO2 has been recognized as a green house gas

(GHG), and therefore potentially environmentally harmful. Coal power plants with CCS lower CO2

emissions up to 90%, but their adoption relies on being able to maintain efficiency and low costs for

power plant owners. The three carbon capture (CC) technologies examined in a case study of 7 different

potential CC systems were:

-Absorption

-Gasification

-Oxy-coal combustion

CO2 absorption by the standard solvent MEA was found to be very energy consumptive,

therefore leading to the highest Cost of Electricity (COE) and Mitigation Cost (MC) for any of the 7 cases.

Newer technologies such as Integrated Gasification and Combined Cycle (IGCC) and Oxy-coal

combustion power plants offer higher efficiencies and therefore better potential as CC sources. Oxy-

coal combustion has yet to be scaled up from pilot plant prototypes, but improvements to its design

through more efficient Air Separator Unit (ASU) development are possible. An IGCC power plant with

80% CO2 capture performed best due to its relatively low Energy Penalty (EP), COE, and MC. However,

research should be continued for both gasification and oxy-coal combustion to determine which design

is ultimately more feasible for large scale implementation.

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Introduction

The Intergovernmental Panel on Climate Change (IPCC) has recognized that the continuous release

of CO2 emissions at the gigaton level is likely to affect the climate.ii While the direct affect of CO2 on the

environment is still unclear, global and national limits on its release including the Kyoto Protocol call for

reduced Green House Gas (GHG) emissions. The European Union uses a cap and trade approach to reducing

CO2 levels where an overall quota for carbon dioxide emissions is set and private companies are allowed to

buy and trade the right to release CO2. Furthermore, some countries such as Norway further tax the release

of carbon dioxide to encourage reductions. On top of these direct governmental imposed economic

incentives, the reduction of GHG levels is important because the effects of climate change are predicted to

shave off anywhere from 1 to 12% of GDP in many countries due to shifting climate zones, floods, droughts,

and rising sea levels.xiii While moving to alternative carbonless forms of energy such as wind and solar

power offer a promising future, at best they can be projected to contribute 20% of U.S. energy within the

next 10-20 years because of economic barriers.viii

Carbon dioxide emissions comprise 77% of total anthropogenic (man-made) GHG emissions with 38

gigatonnes (Gt) released in the year 2004.xx Over 98% of CO2 emissions come from the combustion of fossil

fuels including coal, natural gas, and petroleum.xxi More specifically, the combustion of coal makes up 33%

of total energy related CO2 emissions and 81% of CO2 emissions from the electric power sector in the United

States.xxi So clearly, fossil-fuel, and more specifically coal, power plants become a target for CO2 reduction.

Carbon capture and sequestration (CCS) is the main technology talked about to combat this

problem. CO2 is taken out of the gases produced from coal combustion (flue gas), concentrated, and

stored somewhere underground so that it does not escape into the Earth’s atmosphere. There are three

basic categories of carbon capture systems and various ways to store the CO2 once it has been captured.

Post combustion capture is the most widely used today, employing the selective absorption of CO2 from

the flue gas into a chemical solvent. The second is pre-combustion gasification, where coal is gasified to

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form synthesis gas (CO + H2) and CO2 can be separated before the hydrogen gas is burned as fuel. Oxy-

fuel combustion burns coal in pure oxygen instead of air, resulting in relatively easy to separate

components of water vapor and CO2 in the flue gas stream. Once the CO2 has been captured, itmust be

stored. Many studies have shown that CO2 can be stored in underground geologic formations, deep sea

saline aquifers, or can be reused in industrial processes.xxii

Carbon capture technologies are still relatively new for implementation in the energy sector,

although the idea has been around for decades. At present, no full-scale CO2 capture systems have

been used on coal power plants, and very few are in place for cleaner-burning natural gas power plants.

This report takes a comprehensive look at the aforementioned technologies and their overall feasibility

for large-scale application to coal fired power plants. The mechanisms and processes of the three

options are described and then evaluated for their efficiencies of design and capture. Several cases are

used to compare their economic viabilities. The numbers used for comparison are fairly standard,

including the Energy Penalty (energy lost to CO2 capture), Cost of Electricity, and Mitigation Cost

($/tonne CO2 captured).

Sequestration

Carbon dioxide sequestration is ultimately the key to making carbon capture technologies a

possibility. Concentrated CO2 is pumped underground into sealed, naturally occurring geological

formations, theoretically remaining there indefinitely. The best example of CO2 sequestration is the

Sleipner natural gas power plant owned by Statoil in Norway that has pumped over 1 million tons of

highly pressurized CO2 annually into sealed porous undersea sediments since 1996.xiii Figure 1 shows

several of the methods for sequestration, including saline aquifers, depleted oil and gas reserves, and

enhanced oil recovery, which has the potential of increasing petroleum yields. Studies have shown

successful subterranean storage of CO2, but the long term effects are not fully understood. The largest

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fear is leakage over time, and economically modeling the leakage effects is only in very early stages.ix

However, literature suggests that sequestration is a practical technology, with minimal amounts of CO2

expected to release over time.i Regardless, one huge hurdle for CCS remains public acceptance.

Therefore, further investigation of the effects of pumping CO2 underground is needed.

Absorption

Absorption is defined as the physical or chemical transfer of the concentration of an atom or

molecule from one phase into another. Because coal is burned with air, which is 79% relatively inert

nitrogen by volume, carbon dioxide is not the primary constituent in the flue gas. In fact, when coal is

combusted, the flue gas is full of many different molecules, including toxic sulfur dioxide, nitrogen

oxides, water vapor, carbon monoxide and dioxide, and particulate matter. A typical coal power plant

combusts coal to form a gas stream that is 14% CO2 by volume, so the absorption of CO2 has to be highly

selective in order to only absorb CO2 out of the flue gas.

Fig. 1 CO2 Sequestration Optionsxxiii

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The standard solvent used for CO2 chemical absorption is a 30% Monoethanolamine (MEA) solution.

Physical absorption solvents will be brought up in the gasification section, as they are used to absorb CO2

more effectively at higher pressures. In an aqueous solution, MEA acts as a weak base, which is capable of

neutralizing the acidic molecule CO2. The reaction forms a carbamate molecule as shown below.

2CH2CH2(OH)NH2+CO2＝CH2CH2OH-NH3+ +CH2CH2OH-NHCOO- (1)

Two moles of MEA are required to absorb CO2 through this reaction, leading to a theoretical loading

capacity of 0.5 (mole CO2/mole solvent). In general, higher loading capacities are preferred in solvents and

lead to more efficient capture results. Organic chemical properties such as substituted hydroxyl groups near

the amine and other secondary pathways contribute to higher loading capacities, such as the CO2 hydration

pathway to form bicarbonate shown below .xiv, xv

R1R2R3N+ CO2 + H2O＝HCO3- + R1R2R3NH+ (2)

The process flow scheme of a typical amine-based capture system is shown in Figure 1.xiv,xv Flue gas

entering the process at close to atmospheric pressure is cooled to the required operating temperature

around 40-60℃. The lean solvent (i.e. solvent with low content of CO2) is pumped into an absorption tower

to contact with cooled flue gas. The CO2 is absorbed in the solvent, forming carbamate and other molecules,

and the CO2 clean flue gas exits the top of the absorber and vents to the atmosphere.

Rich solvent (i.e. high content of CO2) exiting the bottom of the absorber tower is then pumped to the

top of the stripper tower. The stripper tower typically operates at 100-150℃ and at higher pressure than

the absorber, leading to the reverse reaction of Eq. 1-2. CO2 is released from the stripper tower, and is

condensed for storage. The lean solvent is cooled by the heat exchanger and recycled back to the Absorber

Tower. Typically, 75-90% of the CO2 is captured using this technology, producing nearly pure CO2 (>99%)

product stream.xvi

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MEA is a good solvent for CO2 absorption for several reasons, including its high pH, CO2 absorption

capacity, and availability. However, MEA presents several problems as a solvent on a large scale as well,

mainly solvent loss due to evaporation and corrosion. MEA will react with oxygen in excess to create toxic

degradation products that will lower plant efficiencies over time.xix MEA captures 90% of CO2 from coal

power plants, but requires a large energy investment to do so. The largest losses come from solvent

regeneration, where 4.2 GJ/tonne CO2 captured are required to heat and cool the amine solution during its

cycle in the desorption process.xx

It is worth noting that much research has been put into finding other viable solvents for CO2

absorption, including amino-acid salt solutions. The absorption of CO2 into amino-acid salts is chemically

very similar to that of MEA, but as an emerging design, there are currently several issues for using amino

acid salt solutions on an industrial scale. The biggest obstacle is that amino acid salt solutions require a

membrane placed in between the solvent and the flue gas, which would reach extremely large dimensions

for full-scale capture. The economics of this kind of absorption are compared to that of MEA later, but are

rough estimates as only small scale CO2 capture has been demonstrated to date.

Figure 2: Chemical Absorption and Desorption Process for Cyclic CO2 Capture and Releasexvii

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Gasification

Coal gasification technology has been around for hundreds of years. In the 1800’s coal was burned

to create a gas composed mainly of carbon monoxide (CO) and hydrogen (H2) called synthesis gas (syngas)

used for powering homes and buildings until technology for extracting natural gas came about.vi The design

changes to make it usable as a CO2 capturing device including pre-combustion CO2 absorption solvents are

already available, but no commercial coal fired power plant using gasification captures CO2. Coal

gasification occurs by heating coal to high temperatures, pressurizing it, and then flushing oxygen and water

vapor across it. Coal gets oxidized by the oxygen and water to form syngas by the reaction below: x

3C (i.e., coal) + O2 + H2O → H2 + 3CO (3)

Typically, some of the coal is also fully combusted to CO2. In order to fully capture the carbon

product from the coal, the water gas shift reaction is employed to get a final product of carbon dioxide and

hydrogen gas:

CO + H2O → CO2 + H2 (4)

The hydrogen gas can then be used as an energy source, while the CO2 can be easily selectively

absorbed at its high concentration in the gas stream using physical solvents such as Selexol. Selexol absorbs

CO2 effectively only at high pressures (~300 psi), and it has been proven to be more effective than MEA and

other solvents at the kinds of pressures that exist after the gasification process which produces a gas stream

of higher CO2 concentration than a traditional coal combustion with air.

Coal power plants using gasification are generally called Integrated Gasification and Combined

Cycle (IGCC) power plants. The combined cycle is a steam turbine cycle re-using waste heat from the

gasification of coal in order to increase energy efficiency. In this way, energy is produced from two

processes: the combustion of hydrogen gas and the steam turbine cycle. Figure 3 shows an outline of

the process of an IGCC plant. Coal and air are input, some of the oxygen is stripped from air in order to

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gasify the coal, and then the CO2 and other unnecessary products (such as sulfur dioxide) are separated

and captured. As can be seen in the diagram, power production comes from the two turbines, one for

combustion and one for steam. In order for an IGCC to work with carbon capture, some of the additions

would be oxygen production, a shift reactor (for the water gas shift reaction), and a solvent absorption

tower for the Selexol process.iv In order for this to be a completely viable form of energy production,

hydrogen powered turbines would need to be improved. Because of the high combustion temperature

of H2, existing turbines can only accept gas containing 45% H2, but higher efficiencies would be

achievable if the gas stream could burn a fuel more concentrated in H2.

Oxy-Coal Combustion In a conventional coal combustion power plant, air and coal are supplied to a furnace where the

oxygen in the air is combusted with coal in order to produce heat. The nitrogen in air moderates the

furnace temperatures and facilitates heat transfer for steam production which spins the steam

generators producing electricity.iii Because air is composed of 79% relatively inert Nitrogen, the flue gas

is only 14% CO2 and must be separated by selective and energy intensive amine or membrane processes

(as discussed in the absorption section). However, the combustion of coal in pure oxygen creates a flue

Figure 3: IGCC Process xxiv

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gas highly concentrated in CO2 and H2O, therefore making separation much more energy efficient.

Theoretically, the CO2 concentration could reach close to 80% due to the atomic makeup of coal, but

because the heat of combustion of pure oxygen is so high, some of the combusted coal gas (CO2 and

H2O) must be recycled in order to moderate temperature as the Nitrogen in air would do normally.iii The

combusted coal gas that is not recycled can then be separated to get pure CO2 by a distillation tower. In

the distillation tower, the flue gas is cooled to around -56ᵒ F in order to condense out the excess O2 and

H2O, thereby creating a product extremely concentrated in CO2 for capture that can be condensed and

collected.ii This process is much less energy intensive than absorption processes required for MEA and

Selexol CO2 absorption.

Figure 4 shows a flow chart for the inputs and outputs of oxy-coal combustion. The biggest

challenge to making oxy-coal combustion on an industrial scale is the Air Separation Unit (ASU), which

intakes air and separates O2 from N2.ii An ASU is also needed for IGCC plants in order to get pure oxygen

to gasify coal; however, less oxygen is required for gasification than combustion so an ASU for a full

scale oxy-coal combustion power plant would need to be much larger. Presently, ASU’s have reached

sizes capable of producing 4200 tons per day (tpd) O2. This is adequate for a 500 MW IGCC power

plant’s needs, but for a 500MW oxy-coal plant, roughly 10,300 tpd O2 would be required.v

Figure 4: Oxy-Coal Combustion Processiv

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Case-Study

Several cases for different kinds of coal power plants were examined to compare their

theoretical full scale performances. All technologies were based on the specs for an average size US coal

power plant (close to 550 MW). Two baselines were used to compare efficiencies. The first was a

traditional pulverized coal combustion power plant with no carbon capture (550 MW output), and the

second was an IGCC power plant with no carbon capture (577MW output), the industry standard for

new coal power plant design. For cases 1- 3, numbers and assumptions were taken from studies from

Babcock and Wilcox, while for cases 4-6, numbers were taken from Ordorica-Garcia et al.ii ,iv

Case 1: -MEA Absorption with 90% CO2 capture (standard capture rate for MEA absorption systems) on a

standard pulverized coal power plant. Case 2: -Super Critical (SC) Oxy-coal combustion (242 bar, 1100-1150 F). Super critical combustion operates at

pressures above the critical point of water, meaning water exists as a super-critical fluid instead of separated phases of liquid and vapor. Operating at higher temperatures and pressures allows for higher plant efficiencies.

-95% molar O2 fed in for combustion (not pure, but more economically viable than pure >99% molar O2) -550 MW power output -Design assumed to be put in place 2015-2020; however, current design of ASU’s was used in calculating

costs (improvement on ASU design by this time is likely due to research and development) Case 3: -Ultra Super Critical (USC) Oxy-coal combustion (270 bar, 1350-1400 F). Ultra super critical combustion

is the same idea as SC combustion, just at even higher pressures and temperatures. This kind of combustion is still not completely understood, as proper materials for combustion chambers at such extreme conditions are still under experimentation.xi

-All other specifications the same as Case 2 Case 4: -IGCC with 80% CO2 capture -Power output is 488 MW Case 5: -IGCC with 60% CO2 capture -Power output is 512 MW

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0

5

10

15

20

25

30

35

40

45

% e

ffic

ien

t

Graph 1: Plant Efficiency

Case 6: -IGCC with CO2 and H2S (sulfur dioxide) Co-capture. CO2 and H2S are removed from the flue gas

simultaneously using a single absorption process. Normally H2S must be captured separately during coal combustion because it is a monitored toxic compound, so combining H2S capture with CO2 capture means only one acid gas absorber needs to be built instead of two.

Case 7*: -CO2 absorption with CORAL ™ solvents (brand of a specific amino-acid salt solution developed by

private European research group, TNO). CORAL stands for CO2 Removal Absorption Liquid. * Cost of electricity and overall plant efficiency could not be ascertained.xix

Analysis:

Energy Efficiency:

Not surprisingly, the worst plant efficiency is that with MEA absorption. Plant efficiency is

defined as the percent of energy stored in the fuel source (coal) that is ultimately converted to

electricity. The large energy losses due to the heat required for solvent regeneration are by far the most

costly, making MEA absorption a highly unfeasible technology. The Energy Penalty (percent of total

input fuel that must be used to CC processes, EP) for MEA is 23%, which is the highest EP for all cases

examined.

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Graph 1 shows several options, particularly USC oxy-fuel and all IGCC cases with carbon capture,

offer comparable plant efficiencies to that of a conventional pulverized coal power plant. However,

these too suffer large EP’s when compared to a standard IGCC plant running with no carbon capture

(baseline 2). The EP for an IGCC with 80% capture is 17%, mainly due to the added energy intensive ASU

and CO2 separation towers. Oxy-coal combustion shows efficiencies below those of IGCC plants, which

most likely is due to the energy intensive larger scale ASU’s it requires. While the fact that carbon

capture technologies can reach efficiencies equal to those of coal power plants already in use, the main

roadblock is cost.

Cost of Electricity

Investing in an IGCC power plant requires being able to front a steep capital cost. They are a

well proven technology that produces better returns in the long run than conventional pulverized coal

power plants, but construction costs are much higher. This is due to a much more complicated design,

as can be seen in Figure 3. A typical IGCC without carbon capture requires around $1 billion in

investments to start up. This number only increases when adding on CC technology: an additional $166

million for 80% capture and $141 million for 60% capture.iv Current projections show the capital cost for

oxy-fuel combustion plants with carbon capture to be lower than that of IGCC plants. Graph 2 shows

the increase in cost of electricity (COE) for cases 1-6 when compared to the COE for a conventional coal

plant with no capture (baseline 1). The COE takes into account both capital and running costs. Again,

MEA projects as the most expensive, while IGCC with CO2 capture achieves the best results.

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Cost of electricity is probably the most important parameter for potential coal power plant

private investors because the COE is the greatest burden to making a coal power plant profitable. The

profitability of a coal power plant lies in the ability to sell electricity at a competitive price, so the large

percent increases in COE as can be observed from Graph 2 (all above 30% except for IGCC Co-capture)

do not bode particularly well for its implementation at the private level in the near future. Some of

these costs can be mitigated through governmental sponsorship; however, if the economy moves

towards being greener as has been predicted for around 2020, power plants will eventually be

competing evenly with carbon capture technology implemented across the entire energy sector.ii

Environmental Impact:

Mitigation Cost (MC) is the best parameter to compare the environmental impact of different

power plants with carbon capture while keeping cost in mind. MC is defined by: iv

0

10

20

30

40

50

60

70

MEA 90% SC-oxyfuel USC-oxyfuel IGCC 80% Capt

IGCC 60% Capt

IGCC 80% co-capture

% in

cre

ase

in C

OE

Graph 2: % increase in Cost of Electricity

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0

5

10

15

20

25

30

35

40

45

50

($/t

on

ne

CO

2 a

void

ed

)

Cost for avoided CO2

In the previous equation, E stands for CO2 capture (tonne CO2/kwh) and the subscripts ref and

cap stand for the reference and capture plants respectively. For reference, baseline 1 (conventional coal

power plant) is generally used. The units of MC are therefore $/tonne CO2 captured. This shows the

direct cost in order to stop CO2 from being emitted. Graph 3 shows the MC for cases 1-7. Oxy-coal and

IGCC capture plants (cases 2-5) all have relatively similar MC’s, with IGCC 80% capture the lowest for

these 4 cases.

Special Cases

Case 6, IGCC with Co-capture, appears to be the clear-cut winner for overall feasibility when

looking at Graphs 2 and 3. Cost is extremely low compared to all other cases, and in fact only a 7.6%

increase in COE is observed if co-capture is instead compared to an IGCC plant without CO2 capture

(baseline 2). The reason for this small increase in electricity cost is due to lowered capital costs. The

lowered capital costs result from a much simplified absorption process requiring one large absorption

tower for both H2S and CO2 instead of two separate ones, as well as an inherent increase in the flue gas

stream pressure for this design that increases absorption efficiencies. However, the main flaw of this

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system is not covered directly in the metrics of the comparisons used for this report: nobody has really

thought of a use yet for a toxic acid gas composed of H2S and CO2, the product of Co-capture. For

normal CC processes, because the collected CO2 is pure, it can be used for a variety of purposes. Many

commercial processes require concentrated CO2 (such as soda production or greenhouses), so it does

have some marketability. Beyond that, it has been proven to a good extent to be safe when

sequestered underground. Sulfur dioxide, on the other hand, has much more adverse effects when

released into the environment including being a precursor to sulfuric acid (which causes acid rain) and

particulate matter (which correlate to adverse climate change effects).xii If captured separately from

CO2, it too can be re-used industrially by being converted back into usable sulfur products, but

concentrated with CO2 it has little value. Also, because of the strong environmental awareness and lack

of understanding of how H2S would store underground, sequestering a product stream from a Co-

capture plant is currently not a legitimate option.

Case 7 involves the possibility of a membrane system for absorption of CO2 using a specific

amino acid salt solution (CORAL ™). The calculated MC comes from a cost estimate analysis done by the

TNO, the company who owns (and is therefore promoting) CORAL ™ solvents.xix Very large assumptions

are made for this process for a full scale coal power plant, as only bench scale simulations have been

performed. The energy consumption levels are almost solely based on the higher loading capacities of

CORAL ™ versus MEA (92 kg/m3 and 55 kg/m3 respectively), while many other chemical and absorption

design factors affect the MC. The main point to take away from the research done by the TNO is that

CORAL ™ solvents do show good potential to be more efficient than MEA for post-combustion capture,

however exactly how much more efficient has yet to be concretely determined. Their comparison to

newer technologies like gasification and oxy-coal combustion is sketchy at best.

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Retro-Fitting

One other factor for the overall feasibility of large scale implementation of CC technology is how

it can be applied to pre-existing coal power plants, or retro-fitting. MEA absorption requires the

addition of spacious absorption and stripper towers onto a coal power plant’s facilities, and the addition

lowers the plant’s energy efficiency by a large amount. Oxy-coal combustion has been shown to be a

viable retro-fit because all the additions to a standard pulverized coal power plant can be done

upstream and downstream of the combustion chamber, including adding an ASU and flue gas recycler.

Gasification is a process that is harder to integrate into a previously designed combustion coal power

plant due to the fact that it requires an entirely new chamber for gasification instead of combustion, as

well as an added steam turbine in order to be efficient.

While it is true that in order to achieve any sort of substantial reduction in global CO2 emissions

from coal power plants pre-existing plants would have to be dealt with, CO2 capture really only makes

sense for newer high efficiency plants. This is due to the EP as discussed earlier. In order to capture the

same amount of CO2, higher efficiency power plants require less energy.i This is seen when comparing

the EP for MEA absorption (23%), the standard to for retro-fits, to that of IGCC with 80% capture (17%),

a retro-fit for a newer more efficient IGCC power plant. Some literature suggests that because many of

the coal power plants in the United States are expected to reach the end of their lifespan around 2020,

during the same time that IGCC with CO2 capture and oxy-coal combustion become more economically

feasible, older plants could just be phased out for more energy efficient designs with CC.

Conclusion

Coal power is such a vital part to the economy of the United States, where over half the energy

produced comes from coal-fired power plants, that phasing out its use quickly is simply unfeasible.

Bridging the gap to the next generation of re-usable clean energy technologies requires tackling the

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pollution problem of today. Coal power plants can be made cleaner burning by using different forms of

CCS to keep CO2 emission levels low. Subterranean sequestration is still under much research for long

term effects, but is generally viewed by the scientific world as a safe form of CO2 storage.

Several different CC technologies offer potential for installation on large scale coal power plants.

MEA absorption is the most industrially understood, but has well-observed low energy efficiencies due

to the inherent solvent heating and cooling regeneration cycle. While it does achieve the ultimate goal

of capturing around 90% of the CO2 in the flue gas of a coal power plant, the costs associated with it,

including both COE and MC, are much too high when compared to the newer technological alternatives.

Oxy-coal combustion still has room for improvement in design due to the sizeable energy losses

comes from the required large ASU. ASU technology has been a focal point over the last ten or so years

and will continue to be in the near future in order to make both Oxy-coal combustion and coal

gasification more efficient processes. The current standard method for air separation is cryogenic

separation (cooling the air to a low enough temperature to condense out the oxygen). Since 2000, a

20% decrease in power consumption by this method has been achieved, and another 10% reduction is

expected by 2015.v Because of this, along with the fact that Oxy-coal combustion has only been tested

at small scales, the potential for future improvement of any of the three main technologies discussed is

probably greatest for Oxy-coal.

That being said, when comparing the three main variables discussed in this paper, the most

favorable choice looks to be coal gasification with carbon capture. IGCC plants are an efficient design

for coal power, so they offer a good starting point for carbon capture systems to be added onto. Case 4

(IGCC with 80% capture), offers the best overall results. It has the lowest MC of any case (outside of 6

and 7), and has an EP very close to that of IGCC with 60% capture and Co-capture. The main knock on

this design therefore is the COE, which is 40% above the current standard. When compared to the other

carbon capture technologies in question, it still has a fairly low COE, but in order to make this kind of

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power plant with carbon capture economically competitive, major shifts in the economy towards

greener thinking will have to happen.

Ultimately, higher incentives will have to be made to energy producing corporations in order for

carbon capture to catch on. As of today, no full scale coal power plant uses carbon capture because the

costs associated with are too much of a hindrance. However, green design is an increasing factor of

importance for newer coal power plants, and CCS does hold serious promise in reducing GHG emissions.

While this report has demonstrated that there are some fairly efficient and promising methods of

carbon capture, improvements will continue to be heavily researched and developed due to the large

environmental and economic potential they offer.

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References

i. Gielen, Dolf, and Jacek Podkanski. Prospects for CO2 Capture and Storage. Paris: International Energy Agency, 2004. Print.

ii. Farzan, H., S. Vecci, D. McDonald, and K. McCauley. "State of the Art of Oxy-Coal Combustion Technology for CO2 Control from Coal-Fired Boilers." Babcock and Wilcox, 17 May 2007. Web. 17 Dec. 2010. <http://www.icac.com/files/public/B&W_Br_1793_Farzan.pdf>.

iii. "Oxy-Coal Combustion Overview." Babcock and Wilcox, Mar. 2007. Web. 17 Dec. 2010. <http://www.icac.com/files/public/B&W_Oxycomb_Overview_031507.pdf>.

iv. Ordorica-Garcia, Guillermo, Peter Douglas, Eric Croiset, and Ligang Zheng. "Technoeconomic Evaluation of IGCC Power Plants for CO2 Avoidance." Energy Conversion and Management 47 (2006): 2250-259. Print.

v. Tranier, Jean-Pierre. "Air Separation Unit for Oxy-Coal Combustion Systems." Air Liquide, 9 Sept. 2009. Web. 17 Dec. 2010.

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