Oxy-fuel combustion technology for coal-fired power generation

B.J.P. Buhre, L.K. Elliott, C.D. Sheng, R.P. Gupta, T.F. Wall *

Cooperative Research Centre for Coal in Sustainable Development, Discipline of Chemical Engineering, The University of Newcastle,

Callaghan, NSW 2308, Australia

Received 10 December 2004; accepted 30 July 2005

Abstract

The awareness of the increase in greenhouse gas emissions has resulted in the development of new technologies with

lower emissions and technologies that can accommodate capture and sequestration of carbon dioxide. For existing coal-fired

combustion plants there are two main options for CO2 capture: removal of nitrogen from flue gases or removal of nitrogen

from air before combustion to obtain a gas stream ready for geo-sequestration. In oxy-fuel combustion, fuel is combusted in

pure oxygen rather than air. This technology recycles flue gas back into the furnace to control temperature and makeup the

volume of the missing N2 to ensure there is sufficient gas to maintain the temperature and heat flux profiles in the boiler. A

further advantage of the technology revealed in pilot-scale tests is substantially reduced NOx emissions. For coal-fired

combustion, the technology was suggested in the eighties, however, recent developments have led to a renewed interest in

the technology. This paper provides a comprehensive review of research that has been undertaken, gives the status of the

technology development and assessments providing comparisons with other power generation options, and suggests research

needs.

q 2005 Elsevier Ltd. All rights reserved.

Keywords: Oxy-fuel combustion; pf coal combustion; CO1 capture

Contents

1. Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 284

2. Oxy-fuel technology description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 285

3. Technology status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 287

3.1. Design and operational issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 287

3.1.1. Heat transfer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 287

3.1.2. Environmental issues; gaseous emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 288

3.1.3. Ash related issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 288

3.1.4. Combustion; ignition and flame stability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 288

3.2. Laboratory studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 288

3.3. Pilot-scale studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 288

3.3.1. Summary of conclusions from pilot-scale studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 292

3.4. Findings on heat transfer assessments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 292

Progress in Energy and Combustion Science 31 (2005) 283–307

www.elsevier.com/locate/pecs

0360-1285/$ - see front matter q 2005 Elsevier Ltd. All rights reserved.

doi:10.1016/j.pecs.2005.07.001

* Corresponding author. Tel.: C61 249 216179; fax: C61 249 216920.

E-mail address: terry.wall@newcastle.edu.au (T.F. Wall).

B.J.P. Buhre et al. / Progress in Energy and Combustion Science 31 (2005) 283–307284

3.5. Findings on ignition characteristics and flame stability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 293

3.6. Findings on rate of char combustion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 293

3.7. Findings on emission control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 293

3.7.1. CO2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 293

3.7.2. NOx . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 293

3.7.3. SO2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 294

3.7.4. Submicron ash particles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 295

3.7.5. Trace elements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 295

3.8. Full scale techno-economic evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 295

3.9. Summary of techno-economic assessments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 301

3.10. Technology comparisons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 302

4. Research needs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 302

4.1. The heat transfer performance of new and retrofitted plants and the impact of oxygen feed concentration and CO2

recycle ratio. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 303

4.2. The gas cleaning required. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 303

4.3. Assessment of retrofits for electricity cost and cost of CO2 avoided. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 304

4.4. The combustion of coal in an O2/CO2 atmosphere, including ignition, burn-out, and emissions. . . . . . . . . 304

4.5. The development of new, and less expensive, oxygen generation technology. . . . . . . . . . . . . . . . . . . . . . 304

5. Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 304

Acknowledgements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 305

References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 305

1. Introduction

Energy production from fossil fuel combustion

results in the emission of greenhouse gasses, the

dominant contributor being CO2. Public awareness

and legislation have led to a policy of reduction of

greenhouse gas emissions in most economically well-

developed countries, with the regulations partially

driven by (international) initiatives such as the Kyoto

protocol and the Intergovernmental Panel on Climate

Change [1].

It is well known that greenhouse gas emissions

from energy production can be reduced by the use of

alternative energy sources such as nuclear power and

renewable energy sources. Renewable energy sources

are expected to become increasingly important for

our future energy demand, however, until these

sources can reliably produce significant amounts of

energy, the immediate energy demand is likely to be

met by conventional fossil fuel combustion, a trend

observed by organizations assessing energy policy

and use [2,3].

Over the past decade, the role of coal as an energy

source for the future has gained renewed interest for its

proven stability in supply and cost and it is, therefore,

likely that coal will remain in an important position in

the energy mix in the foreseeable future.

The effect of greenhouse gasses on global climate

change has been acknowledged by many governments

worldwide, and the reduction of the emissions of these

gasses is becoming increasingly important. To maintain

the position of coal in the global energy mix in a

carbon-constrained world, the greenhouse gas emis-

sions emitted from its utilization must be reduced. To

reduce greenhouse gas emissions from coal-fired power

generation, several possibilities can be perceived:

† Improving efficiency of power plants,

† Introduction of combined cycles—as-fired or IGCC,

which can reach high thermal efficiencies,

† Replacement of hydrocarbon fuels with renewable

resources,

† Capture and storage of CO2 from conventional

plants.

Renewable energies may hold hope for reducing

greenhouse gas emissions in an extremely long time

frame. Renewable resources, such as biomass, which

can be used to directly replace coal and oil in

combustion processes are not available in the quantities

required for substantial substitution.

In Australia, over 85% of the current electricity is

generated in pf coal-fired power stations [4]. With the

installation of new capacity which uses modern

technologies such as supercritical and ultra-supercriti-

cal boilers, the efficiency of this installed capacity

continues to increase, a trend occurring worldwide.

Incremental reduction of greenhouse gas emissions

can be achieved by the stepwise implementation of

more efficient coal-fired power plants, however, to

make a significant reduction in emissions, the CO2

Furnace Heat

ExtractionGas

Cleanup

Coal + O2

Hot RFG Cold RFG

Stack

CO2

Compression /Sequestration

Fig. 1. General flow sheet for oxy-fuel combustion.

B.J.P. Buhre et al. / Progress in Energy and Combustion Science 31 (2005) 283–307 285

generated from coal utilization needs to be captured and

stored (sequestered).

Several technologies are being developed for CO2

capture and sequestration from coal fired plants that

include [5]:

(a) CO2 capture from plants of conventional pf design

by scrubbing of the flue gas

(b) IGCC with an air separation unit to provide O2.

(c) Oxy-fuel combustion with the oxygen diluted with

an external recycle stream to reduce its combus-

tion temperature.

(d) Oxy-combustion with an internal recycle stream

induced by the high momentum oxygen jets in

place of external recycle. This technology is now

widely used in the glass industry and, to a lesser

extent, in the steel industry.

(a) Chemical looping. This involves the oxidation of

an intermediate by air and the use of the oxidized

intermediate to oxidize the fuel.

This review covers a, b, and c, as these are

considered the closest to commercial application. The

parasitic losses of CO2 compression for storage (also

termed sequestration) is independent of the technology

producing the CO2.

CO2 from conventional combustion processes is

present as a dilute gas in the flue gas, resulting in costly

capture using amine absorption. CO2 capture is more

easily achieved from a concentrated CO2 stream, which

can be achieved by firing fuels with oxygen to obtain a

sequestration-ready gas stream. The latter technique is

termed oxy-fuel combustion. In this technique, the

oxygen stream is usually diluted by recycled flue gas

(RFG).

Studies on the application of this ‘oxy-fuel’

technology to pulverised coal combustion power plants

are presented in this review, including laboratory and

pilot-scale experiments and full scale evaluations. Only

one review on this topic has been previously published,

however, this review only presents the studies done by

Ishikawajima-Harima Heavy Industries [6].

There are no full-scale plants using oxy-fuel

combustion in operation. However, laboratory work

and theoretical studies have provided understanding of

the relevant design parameters and operational issues.

Globally there have been some investigations in pilot-

scale facilities in the United States, Canada, Europe,

and Japan, viz., Air Liquide (US), CANMET (Canada),

International Flame Research Foundation (IFRF), and

Ishikawajima-Harima Heavy Industries (IHI), which

have been used to study the technology. Studies have

also assessed the feasibility and economics of retrofits

and new power plants.

Several recent assessments have compared oxy-fuel

technology with post-combustion capture and IGCC

technologies for CO2 abatement cost. These studies,

which are summarized in this paper, indicate that oxy-

fuel combustion is a favourable option but that the

comparison depends on the plant considered and the

associated emissions technologies employed, which are

determined by the regulation regimes of different

countries.

2. Oxy-fuel technology description

Conventional pf coal-fired boilers use air for

combustion in which the nitrogen from the air

(approximately 79% by volume) dilutes the CO2

concentration in the flue gas. The capture of CO2

from such dilute mixtures using amine stripping is

relatively expensive (e.g. [7,8]). During oxy-fuel

combustion, a combination of oxygen typically of

greater than 95% purity and recycled flue gas is used for

combustion of the fuel. By recycling the flue gas, a gas

consisting mainly of CO2 and water is generated, ready

for sequestration without stripping of the CO2 from the

gas stream. The recycled flue gas is used to control

flame temperature and make up the volume of the

missing N2 to ensure there is enough gas to carry the

heat through the boiler [9]. A general flow sheet is

provided in Fig. 1.

The characteristics of oxy-fuel combustion with

recycled flue gas differ with air combustion in several

aspects including the following:

† To attain a similar adiabatic flame temperature the

O2 proportion of the gases passing through the

burner is higher, typically 30%, higher than that for

air of 21%, and necessitating that about 60% of the

flue gases are recycled.

† The high proportions of CO2 and H2O in the furnace

gases result in higher gas emissivities, so that

similar radiative heat transfer for a boiler retrofitted

to oxy-fuel will be attained when the O2 proportion

B.J.P. Buhre et al. / Progress in Energy and Combustion Science 31 (2005) 283–307286

of the gases passing through the burner is less

than 30%.

† The volume of gases flowing through the furnace is

reduced somewhat, and the volume of flue gas (after

recycling) is reduced by about 80%.

† The density of the flue gas is increased, as the

molecular weight of CO2 is 44, compared to 28

for N2.

† Typically, when air-firing coal, 20% excess air is

used. Oxy-fuel requires a percent excess O2 (defined

as the O2 supplied in excess of that required for

stoichiometric combustion of the coal supply) to

achieve a similar O2 fraction in the flue gas as air

firing, in the range of 3–5%. [10]

† Without removal in the recycle stream, species

(including corrosive sulphur gases) have higher

concentrations than in air firing.

† As oxy-fuel combustion combined with sequestra-

tion must provide power to several significant unit

operations, such as flue gas compression, that are

not required in a conventional plant without

sequestration, oxy-fuel combustion/sequestration is

less efficient per unit of energy produced. However,

it is more efficient than a conventional plant with

sequestration due to the significant energy required

to scrub a dilute gas stream prior to compression.

Most evaluations and studies on oxy-fuel technol-

ogy are concerned with the application of coal-fired

pulverised fuel boilers to produce a CO2 rich stream

ready for sequestration. Other studies have con-

sidered its application for oil and gas fired power

plants [11,12].

Coal-fired oxy-fuel combustion has been evaluated

for a number of purposes for some years. In 1982,

the technology was proposed for coal-fired processes

by Abraham to generate CO2 for Enhanced Oil

Recovery [13]. In metal heating furnaces, recycling

of hot recycled flue gas (RFG) was suggested to

reduce furnace size and NOx emissions [14]. More

recently, the driver for studies into oxy-fuel

combustion is two-fold:

(1) Generation of a CO2 gas stream suitable for

sequestration

(2) The potential to reduce cost of pollutant emission

control, with the emphasis on NOx.

There are several process variations, which deter-

mine the unit operations of the detailed flow sheet and

the conditions of the streams, as determined by the

following issues:

† Is the plant purpose built or is it a retrofitted plant?

† What O2 proportions is optimum in the oxidant gas?

† What is the desired CO2 proportion in the product

gas?

† Will CO2 be fully or partially sequestered, and to

what extent must the flue gas be cleaned by de-NOx,

de-SOx or de-Hg plant?

A recent emphasis has been to apply the technology

to obtain a high CO2 concentration from coal

combustion (e.g. [15–19]). Oxy-fuel combustion has

been demonstrated at pilot-scale and CO2 formed

during gasification is currently used commercially for

enhanced oil recovery (EOR), particularly in the United

States [20].

A schematic of a pf coal fired oxy-fuel boiler is

shown in Fig. 2 (adapted from [21]). Oxygen is

separated from air and then mixed with a recycle

stream of flue gases from the boiler. Fuel is fired in

the resulting gas stream and the flue gases are

partially recycled. Water vapour is condensed from

the flue gases to produce a stream of high purity

supercritical CO2.

Oxy-fuel combustion and CO2 capture from flue

gases is a near-zero emission technology that can be

adapted to both new and existing pulverised coal-fired

power stations. In oxy-fuel technology the concen-

tration of carbon dioxide in the flue gas is increased

from approximately 17 to 70% by mass. The carbon

dioxide can then be captured by cooling and com-

pression for subsequent transportation and storage. In

this form oxy-fuel combustion involves modification to

familiar pf coal technology to include oxygen separ-

ation, flue gas recycling, CO2 compression, transport,

and storage. The addition of these operations does bring

possible reduction in availability. The extra cost

associated with implementing sequestration will also

increase capital and operating costs.

CO2 sequestration is an area undergoing strong

development in research and development and will not

be discussed in great detail in this paper. However, it is

noted that there are several methods of CO2 sequestra-

tion which lead to different requirements with respect to

the purity of the gas to be sequestered. Although, all

sequestration options have different requirements with

respect to CO2 purity, the energy requirement for CO2

compression is in all cases reduced as the purity of the

CO2 increases. The following sequestration options are

typically considered:

† Enhanced Oil Recovery (EOR); CO2 can be utilized

in depleted oil and gas reservoirs to increase their

CO2

Intercooler

Compressor

Pre-cooler

Filter

ESP

Stack

ASUOxygen

Pre-heater

Feed water heaterG

as-G

as H

eate

r

GRF/FDFPrimaryFan

Mill

Boiler

Oxygen

Air Intake

Fig. 2. Pulverized coal-fired power plant using oxy firing combustion (adapted from [21,80]).

B.J.P. Buhre et al. / Progress in Energy and Combustion Science 31 (2005) 283–307 287

production; EOR has been widely applied in the

United States, and there were 84 applications of this

technology worldwide in 2003 (e.g. [22]),

† Enhanced Coal Bed Methane (ECBM) production;

by injecting CO2 in unmineable coal seams,

methane can be recovered during the process,

which can then be used for power generation [23].

Coal Bed Methane (CBM) extraction is becoming a

common technology but Enhanced CBM is rare.

† Ocean storage; the ocean is a natural carbon sink

and has significant CO2 storage potential, however

the full impact of CO2 storage and absorption into

the ocean is not completely understood yet [24],

† Storage in deep saline aquifers; storage of CO2 in

deep saline aquifers is a particularly promising

option because of the very large storage potential

and the widespread occurrence of saline aquifers in

the vicinity of large scale CO2 generation sites

worldwide [23]. To date no large scale applications

have been demonstrated.

3. Technology status

There are no full-scale plants using oxy-fuel

combustion in operation. However, theoretical studies

combined with laboratory and pilot-scale studies have

provided an understanding of the relevant design

parameters and operational issues. Some practical

aspects, such as the availability and load following

capability of oxy-fuel plants, are significant issues

requiring demonstrations and full-scale plant

experience.

3.1. Design and operational issues

Several design and operational issues have been

identified in literature. These issues can be categorised

as follows:

3.1.1. Heat transfer

By recycling the CO2 (and possibly H2O) from the

outlet back to the furnace inlet, several changes in heat

transfer can be expected due to the changes in gas

properties. These changes are affected by two main

properties that change during oxy-fuel combustion:

† Gas radiative properties, and

† Gas thermal capacity.

During oxy-fuel combustion, the concentration of

tri-atomic gas molecules in the flue gas increases

drastically and will change the emissivity of the gas.

The major contributor of the heat transfer from a flame

from conventional fuels (and conventional combustion)

is thermal radiation from water vapor, carbon dioxide,

soot, and carbon monoxide [25]. When the concen-

tration of carbon dioxide and water vapor is increased

significantly, such as is the case for oxy-fuel

combustion, the radiative heat transfer from the flame

will change. Tri-atomic molecules absorb and emit

B.J.P. Buhre et al. / Progress in Energy and Combustion Science 31 (2005) 283–307288

radiation in bands corresponding with a change in their

occupancy of a particular energy level. To calculate the

flame emissivity accurately, the absorption and emis-

sion of these bands should be calculated. However,

typical heat transfer calculations use a ‘three grey-one

clear gas’ model to estimate flame emissivity [25,26].

Traditionally, this model is based on conventional

flames with conventional partial pressures of CO2 and

H2O. To calculate the radiative heat transfer from a

flame resulting from oxy-fuel combustion, the ‘three

grey-one clear gas’ model should be validated and/or

modified or replaced by a more accurate band model.

Carbon dioxide and water vapor have high thermal

capacities compared to nitrogen. This increase in

thermal capacity increases the heat transfer in the

convective section of the boiler. However, the amount

of gas passing through the boiler in the oxy-fuel case is

lower, and increased heat transfer in the radiative

section of the boiler results in lower gas temperatures

entering the convective pass. Both of these factors will

act to lower the heat transfer in the convective section

of the boiler. The heat transfer in the radiative and

convective sections of the boiler will need to be

optimized to ensure efficient operation. Different

authors have observed conflicting heat transfer results

due to this required optimization. However, for a

retrofit where furnace heat transfer is matched and a

given flue gas oxygen concentration, the oxy-fuel case

will result in a lower furnace exit gas temperature [10].

3.1.2. Environmental issues; gaseous emissions

Gaseous pollutant formation and emissions change

somewhat during oxy-fuel combustion; the SOx

emissions per tonne of coal combusted are essentially

unchanged; NOx emissions generated per unit energy

are reduced as the recycled NO is reduced or reburned

as it is recirculated through the flame. The effect of oxy-

fuel combustion on trace elements emissions and on fly

ash size distribution have not yet been experimentally

determined, however, it can be expected that the

behaviour of certain minerals (in particular carbonates)

will be affected by the change in environment. (The

decomposition temperature of carbonates will be

increased due to the high carbon dioxide partial

pressures in oxy-fuel [27]). The changes in gaseous

pollutant formation during oxy-fuel combustion have

been analysed by several researchers and is discussed in

more detail in the following sections.

The final compression and liquefaction of the CO2

will result in a stream of non-condensables, which will

include any N2 or Ar in the oxygen stream supplied by

the oxygen plant and resulting from air leakage into

the boiler, excess oxygen from the combustor, and NOx

and SO2. This stream will need to be handled in order to

meet environmental regulations relating to NOx and

SOx emissions, an issue which greatly affects required

unit operations.

3.1.3. Ash related issues

During oxy-fuel combustion, the oxygen concen-

tration in the gas is elevated (around 30% by

volume), which increases particle combustion tem-

perature. This increase in the particle combustion

temperature will affect the associated vaporization of

elements. The vaporised elements often serve as a

bonding agent for ash deposits in the boiler and thus

could affect boiler operation. The effect of oxy-fuel

combustion on submicron ash formation has been

researched [28], however, no studies have been

found that asses its possible impact on deposit

formation and structure.

3.1.4. Combustion; ignition and flame stability

Several studies, with the emphasis on pilot-scale

facilities, have indicated problems with flame stability

and ignition. The discussion below summarises the

results of these aspects in more detail.

3.2. Laboratory studies

After being initially proposed in 1982 and further

stimulated by its promising technology of CO2

sequestration for pulverised coal-fired power plants,

oxy-fuel combustion has attracted great interest in

studies around the world. Laboratory-scale studies

covered many scientific and engineering fundamental

issues on the application of this technology, mainly on

the combustion characteristics and coal reactivity, heat

transfer and emissions. A summary of studies found in

the open literature and their research contents is listed

in Table 1.

3.3. Pilot-scale studies

Laboratory-scale studies are useful in the research to

establish effects on the combustion characteristics.

However, they are not able to adequately simulate

aspects such as heat transfer characteristics and to some

extent, pollutant formation. Pilot-scale studies are far

more effective for this purpose. Table 2 lists some of the

pilot-scale evaluations of oxy-fuel combustion reported

in literature.

Below follows a brief description of the different

studies and their main findings:

Table 1

Summary of laboratory studies

Focus of study Research conditions Reference

Ignition characteristics and flame

propagation speed

Flame propagation in coal-dust clouds in a microgravity facility; Experiments

were carried out in O2/CO2, O2/N2 and O2/Ar atmospheres at oxygen

concentrations ranging between 20 and 95%

[6,31]

Char combustion reactivity and effect

of CO2 presence

Atmospheric and a pressurised thermogravimetric analyses were done using

varying heating rate and O2 (0–100%) concentrations in mixtures of O2–CO2 and

O2–Ar

[49,50]

Char combustion reactivity at

temperatures prevailing in practice

Pulverised coal particles were burned in an entrained-flow reactor, at a gas

temperature of w1700 K and over oxygen concentrations in N2 ranging from 6 to

36%.

[51]

NOx reduction mechanisms in coal

combustion Wwith recycled CO2

Pulverised coal particles were burned in a flat CH4 flame (entrained-flow reactor)

at an oxygen concentration of 21% with varied CO2 concentration in Ar and at a

flame temperature of 1450 K.

[55]

Reduction of recycled NOx at low recycling

ratio and the effects of fuel equivalent ratio,

recycling ratio, coal properties

Pulverised coal particles combust in an entrained-flow reactor at a recycling ration

of 0–0.4 and a temperature of 1123–1573 K.

[52,56,57]

Sulphation of limestone and influences

of various factors on SOx formation

Desulphurization reaction was performed on a fixed bed reactor with a model flue

gas (10% O2 and 80% CO2) at temperatures of 1013–1363 K; CaSO4

decomposition was studied on an entrained-flow reactor with model flue gas

(O2: 0–30%, CO2: 0–100%) at a temperature of 1400–1600 K); and modelling

approach was also used.

[59,60]

CO/CO2 ratio inside char particles A detailed char particle combustion model was used to calculate the CO/CO2 in

char particle and to simulate influence of the variation of CO2 and O2 in the bulk gas.

[28]

Environmental assessment of coal

combustion in O2/CO2 mixture

compared with that in air

Equilibrium calculation was carried out with F*A*C*T to assess the emissions of

SOx, NOx, CO and trace elements, and the ash composition of coal combustion in

O2/CO2 compared to those in air.

[58]

Heat transfer assessment of retrofit The convective and radiative heat transfer in an existing boiler was modelled

using HYSYS to determine the impact of retrofit to oxy-fuel combustion.

[46,47]

Heat transfer assessment of retrofit CFD code combined with a band model to estimate gas emissivity was used to

assess the possibility of retrofitting an air-fired boiler for oxy-fuel combustion.

[45]

B.J.P. Buhre et al. / Progress in Energy and Combustion Science 31 (2005) 283–307 289

The earliest study of coal oxy-fuel combustion in a

pilot-scale furnace was carried out for the Argonne

National Laboratory (ANL) by the Energy and Environ-

mental Research Corporation (EERC) in their 3 MW

pilot facility (cited by [18,29]). The objective of the study

was to characterise the operational issues and to provide a

basis for scaling to full scale. The main findings were:

† With wet recycle, an oxygen concentration of 23.8%

through the burners matched the overall heat transfer

performance of the air firing case. With dry recycle,

the oxygen concentration needed was 27%. The

standard boiler operation practice can be used to

compensate for the deviations of the recycle ratio of

G0.4 from the optimal values.

† The comparable performance and operability of oxy-

fuel combustion were confirmed. Oxy-fuel combus-

tion had a similar in-furnace gas temperature profile

as the normal air-fired combustion. It was found that

oxy-fuel combustion had lower NOx (a decrease of

50%) and SOx emissions, and a high carbon burnout

compared to air firing. No unit basis was given for

the stated SOx and NOx reductions.

† No operational difficulties were found for oxy-fuel

combustion. Therefore the conclusion of the EERC

study was that oxy-fuel combustion ‘may be applied

successfully as a retrofit to a wide range of utility

boiler and furnace systems’

An extensive study done by the International Flame

Research Foundation (IFRF) was done to evaluate the

combustion of pulverised coal in a mixture of O2 and

recycled flue gas with the primary consideration of

retrofitting an existing pf boiler, while increasing CO2

concentration to above 90% for enhanced oil recovery or

CO2 capture [30]. The following conclusions were

drawn:

† Oxy-fuel combustion was technically feasible in a

single wall-fired burner management.

† The optimised oxy-fuel combustion flame yielded

similar radiative and convective heat transfer

Table 2

Summary of pilot-scale studies

Organisation Furnace used Focus of study Reference

EERC and ANL,

USA

10 Million Btu/h utility boiler pilot facility † Demonstrating the technical feasibility of the

CO2 recycle boiler

[29,81,82], Cited

by [18]

† Determining the ratio of recycle gas to O2 for

achieving heat transfer performance similar to air

firing

† Quantifying the observable operational changes

such as flame stability, pollution emissions, and

burnout

† Providing a basis for scaling experimental results

to commercial scale

IFRF, Holland IFRF furnace #1: 2.5 MW, the furnace with

internal square cross-section of 2!2 m and 6.

25 m long and an air-staged swirl burner

† Evaluating the combustion of pulverised coal

during oxy-fuel combustion for retrofitting existing

pulverised coal fired boilers to maximise the CO2

concentration in flue gas.

[30]

† Optimising oxy-fuel combustion conditions to

yield similar radiative and convective heat transfer

performance to air firing

† Evaluating the impact of oxy-fuel combustion on

furnace performance, including flame ignition and

stability, heat transfer, combustion efficiency, pol-

lutant emissions, compared to air operation

IHI, Japan IHI’s 1.2 MW combustion-test furnace: a

horizontal cylinder furnace with 1.3 m inner

diameter and 7.5 m length and a swirl burner

† Combustion characteristics of pulverised during

oxy-fuel combustion

[6,17,31–33,83]

Air liquide,

B&W, USA

1.5 MW pilot-scale boiler with air staged

combustion system

† Demonstrating the technical feasibility of con-

version from air firing to oxy-fuel combustion for

large scale boiler

[19,34]

† Highlighting the impacts of oxy-fuel combustion

process on pollutant (NOx, SO2 and Hg) emissions

and boiler efficiency

CANMET,

Canada

CANMET vertical combustor research facility

(0.3 MW): A cylindrical, down-fired and

adiabatic vertical combustor with an inner

diameter of 0.60 m and a length of 6.7 m.

† Pulverised coal combustion behaviours in var-

ious O2/RFG mixtures, compared with air combus-

tion

[16,36–38]

† Demonstrating the technical factors on the

combustion performance

B.J.P. Buhre et al. / Progress in Energy and Combustion Science 31 (2005) 283–307290

performance to normal air operation, and also yielded

in-flame gas composition trends, combustion per-

formance, flame length and flame stability compar-

able to normal air combustion. The optimum ratio for

recycled flue gas was 0.61 (using the flue gas to

transport the coal, equivalent to 48.5% O2 in

secondary comburent and 3.9% O2 in flue gas), but

was dependent on coal type and combustion facility.

† Oxy-fuel combustion was able to achieve the

combustion performance (e.g. combustion effi-

ciency and pollution emissions) similar to air

operation, and was therefore applicable for pf

boiler retrofitting. The maximum flue gas CO2

concentration was 91.4% or even higher under

fully optimised conditions.

† Oxy-fuel combustion significantly decreases NO2

emissions (mg/MJ coal). Low NOx burner

technology was also demonstrated to be viable

using oxy-fuel combustion technology.

Kiga and co-workers conducted a feasibility study of

CO2 recovery in oxy-fired pulverised coal fired power

plants through investigating the characteristics of

pulverised coal combustion during oxy-fuel combustion

[6,17,31–33]. The studies indicated that:

† Oxygen concentration should be high to raise the

adiabatic flame temperature during oxy-fuel com-

bustion to match that in air combustion. Low oxygen

concentration might lead to an unstable and dark

flame and an unexpected high unburnt carbon in ash

[17]. Pure O2 injection at the centre of the burner

improved the flame stability and decreased the

unburnt carbon content of the ash [17,33].

ESP

Stack

DeNOxDeSOxDeHG

FGR

FGR

FGBoiler

TO

Coal + PO

O2

SO

CO2 capture

Fig. 3. Flowsheet for the Air Liquide study (adapted from [34]).

0

20

40

60

80

100

120

Air-case Oxy-case 1 Oxy-case 2

Unstaged Staged US Regulation100

63

47

29 3124

Fig. 4. Pilot scale results comparing air and O2 combustion NOx levels

(the baseline value in air firing case is 100), adapted from [34].

B.J.P. Buhre et al. / Progress in Energy and Combustion Science 31 (2005) 283–307 291

† NOx conversion (the ratio of fuel nitrogen converted

to NOx) was found to be much lower than that in air

combustion (to about 25%), although it increased

with increasing oxygen concentration [17,31]. It was

concluded that the NOx reduction in oxy-fuel

combustion is due to the rapid reduction of the

recycled NOx into HCN and NH3 in the flame [33].

Gas staging can further decrease the NOx conversion,

while the decrease is less than that in air combustion

[31].

† SOx (reported as S kg/h at a set coal feed rate of

100 kg/h) emission decreased due to the conden-

sation of sulphates in the ducts and the absorption of

sulphur in the ash [31].

A study by Air Liquide together with The Babcock &

Wilcox (B&W) Company demonstrated the combustion

process based on O2 enriched flue gas recirculation for

pf power plant to provide an easy-to-implement option

for multi-pollutant control, including CO2 capture

suitable for retrofitting existing pf boilers [19,34]. The

study was based on a proposed flow sheet for new power

plants shown in Fig. 3.

An American coal was burned in the 1.5 MWth

B&W Small Boiler Simulator and the following

conclusions were drawn:

† A smooth transition from air to oxygen combustion

with favourable flame stability and heat transfer

characteristics could be achieved.

† The experiments showed that the technology

generates significantly less NOx than air firing,

with staged combustion being below the

0.15 lb/MMBtu New Source Performance Standards

required in the US for units installed or modified

after July 1997 [35] (0.15 lb/MMBtu is indicated in

Fig. 4).

† The tests also show effective removal of SOx using

conventional wet FGD equipment, and reported

significant reduction of Hg emission in the oxygen-

fired cases, of the order of around 50% [34]. It must

be noted that these findings were preliminary, and

that these results would need be confirmed in later

studies. To date, these findings have not been

confirmed and must be considered unreliable.

† A great reduction in unburnt carbon in fly ash was

achieved, resulting in improvement in boiler

efficiency due to the use of oxygen.

The Canadian CANMET organisation has a long

history in experimental results and modelling of the oxy-

fuel technology. In their 0.3 MW capacity pilot-scale

combustor, the coal combustion behaviour in various

mixtures of oxygen and CO2 were studied to demon-

strate the effects of several factors on combustion

performance. The factors include oxygen concentration

or recycled ratio, O2 purity, wet/dry recirculation, and

burner performance. The experiments covered the O2

concentration in the feed gas in the range of 21–42%

[16,36,37]. The experimental results were compared

with modelling in CFD code to assess the value of the

B.J.P. Buhre et al. / Progress in Energy and Combustion Science 31 (2005) 283–307292

code for future development [38]. The following

conclusions were drawn:

† CO2 concentration in the flue gas achieved close to

the theoretical value (average 92%)

† Increasing the inlet oxygen concentration increases

the flame temperature. The flame temperature

equivalent to that in air combustion was achieved

with about 35% O2 in the feeding gas. The oxygen

purity (less than 5% N2 in the O2/CO2 mixture) has

no significant effect on the flame temperature.

† NOx emission (mass per unit of energy released from

the coal) decreases compared to that in air

combustion. The reduction was shown to depend

on the oxygen concentration due to the change in the

flame temperature and if recycle occurred and

decreased to less than one third of the emissions

produced in air combustion. However, the difference

decreases significantly even if as little as 3% N2

presented.

† SO2 emission (mass per unit of energy released from

the coal) was not affected significantly by the

variations of O2 or CO2 concentration. The decrease

in SO2 during oxy-fuel combustion is due to SO3

formation and subsequent sulphur retention.

† CO concentration is not a considerable problem.

Increasing the oxygen concentration decreased the

CO emission. The decrease of CO concentration

along the flame is slower compared to air combus-

tion because of high CO2 gas concentration in oxy-

fuel combustion.

† The experimental results compared well with the

modelling efforts, indicating that CFD code could be

used for exploring oxy-fuel concepts.

The previously described experiments were done

using a synthetic mixture of CO2 and O2. Currently, the

facility is being converted to use recycled flue gas and to

determine the effects of moisture, ash, and other

pollutants on the flame characteristics [39]. Initial

investigations using this converted facility suggests

mercury emissions (mass per unit energy released by the

coal) are not changed [40].

3.3.1. Summary of conclusions from pilot-scale studies

† The pilot-scale studies have demonstrated the

feasibility of pulverised coal oxy-fuel combustion

as a technology applicable to pf power plants for

CO2 recovery or capture. No major technical barriers

were found from pilot-scale studies.

† Oxy-fuel combustion technology can be

implemented as an effective retrofit technology for

pf boiler; however, it affects combustion perform-

ance and heat transfer patterns.

† Oxy-fuel combustion achieves clean coal combus-

tion, lowering NOx and possibly mercury emissions

on a basis of mass per unit of energy produced by the

coal and increasing CO2 concentration for recovery

or sequestration. Though the basis (mass per unit of

energy produced by the coal) selected by the pilot-

scale studies to present their results is useful, a far

more accurate basis would be per unit of electrical

energy produced. Oxy-fuel combustion to produce

electricity is far less efficient as the plant must drive

both an oxygen plant and gas compression, which

together typically result in a 9% reduction in plant

efficiency [41]. The expressions of emissions in

terms of concentration (ppm), though avoided by

most authors, is inappropriate as the gas volume is

dependent on gas oxygen concentration and the

recycle ratio. The total gas volume is generally less

in oxy-fuel combustion.

3.4. Findings on heat transfer assessments

Payne indicated that measured heat flux distri-

butions in pilot-scale facilities and calculated heat flux

distributions for full-scale boilers have been obtained

as a function of the amount of CO2 recycle and the

results compared with a baseline case of combustion

in air [42]. The performance of a boiler fired with air

is matched with an amount of flue gas recycle

sufficient to increase the oxygen content in the

‘synthetic air’ to about thirty percent on average,

with small differences at different positions along the

furnace length.

Preliminary heat transfer calculations for retrofits

have also been performed by the University of

Newcastle [43]. The calculations revealed that retro-

fitting of existing boilers with oxy-fuel technology

results in different heat transfer impacts. For the same

adiabatic flame temperature, furnace heat transfer

increases and convective pass transfer decreases. As

the furnace heat transfer is dependant on the furnace

size, the impact is scale (i.e. boiler size) dependant.

Changes to the plant or its operation may be required

to maintain design output by achieving a satisfactory

balance for heat transfer in the different sections of

the furnace. The balancing of heat transfer appears to

depend on the extent of drying of the recycle stream

[44].

B.J.P. Buhre et al. / Progress in Energy and Combustion Science 31 (2005) 283–307 293

Coelho and co-workers recognized the need to

change the gas radiative properties and included a

wide band model in their Computational Fluid

Dynamics (CFD) code [45]. The study concluded that

the capacity of the superheater section needed to be

increased to prevent a capacity reduction of about 5%,

and that a recirculation ratio of 71% resulted in similar

heat transfer profiles considering air leakage into the

boiler [45].

Zheng and co-workers modelled the heat transfer in a

boiler to assess the suitability of retrofitting an air-fired

boiler to oxy-fuel combustion [46,47]. The gas

emissivity was calculated from the correlations for

total gas emissivity for the water vapour and carbon

dioxide suggested by Leckner [48]. The studies

indicated that the lower and upper part of an air-fired

boiler can be made to perform properly without major

modification when converting from air firing to oxy-fuel

combustion [46].

3.5. Findings on ignition characteristics and

flame stability

Kiga and co-workers investigated the ignition

characteristics of pulverised coal in a CO2-rich

atmosphere by measuring the flame propagation speed

in a coal-dust cloud using a microgravity facility which

ensures a homogeneous distribution of coal particles and

avoids mixing by natural convection [31]. It was found

that the flame propagation speed in O2/CO2 environment

is lower than that in O2/N2, which was attributed to the

higher heat capacity of CO2 compared to that of N2. The

higher heat capacity has also been attributed to delayed

flame ignition in oxy-fuel combustion [17,31].

The potential changes in flame stability and pollutant

formation were also noted by other researchers [16,42].

Flammability limits and flame speeds are affected by the

substitution of CO2 for N2 and it was concluded that

CO2 has an inhibitory effect on flame stability. During

pilot-scale experiments, no problems in flame stability

were encountered after addition of a pure oxygen stream

into the combustor [36]. Flame ignition is therefore

delayed in oxy-fuel combustion, but the significance is

related to burner throughput.

3.6. Findings on rate of char combustion

The elevated CO2 concentration surrounding the

burning char particles could result in gasification

reactions contributing to the char mass loss. Varhegyi

and co-workers observed that the kinetics of the char

with O2 reaction was not influenced by the presence of a

high amount of CO2 both in an atmospheric thermo-

gravimetry [49] and in a pressurised thermogravimetry

(Varhegyi and Till, 1999). They measured the reaction

rate of the coal char in O2–CO2 mixtures with varying

O2 concentrations. The negligible effect of CO2 on the

char reaction rate was attributed to the much lower

reaction rate of the char-CO2 reaction than that of char-

O2 [49,50], at the low reaction temperatures 400–900 8C

used in the experiments.

Shaddix and Murphy found that gasification reaction

of the char by CO2 becomes significant under oxygen-

enriched char combustion at temperatures prevailing in

practical processes [51]. Experiments were performed to

burn coal particles in Sandia’s entrained-flow reactor at

a gas temperature of w1700 K and oxygen concen-

trations in nitrogen ranging from 6 to 36%. A char

combustion model, which considered CO oxidation in

the particle boundary layer, was used to interpret the

experimental data, demonstrating that significant CO

oxidation in the boundary layer occurred for results at

high oxygen levels and higher char combustion

temperatures. Model calculations indicated that the

observed char particle temperatures and mass loss rates

under oxygen-enriched char combustion could be

matched well when the char-CO2 reaction was included.

3.7. Findings on emission control

3.7.1. CO2

Laboratory studies indicated that the CO2 concen-

tration in the flue gas of a pulverised coal fired boiler

could reach concentrations higher than 95% during oxy-

fuel combustion [52]. However, the CO2 concentration

attained during pilot-scale experiments is lower due to

air leakage into the furnace; CANMET reported a CO2

purity in their furnace of 92%, 91.4% was attained in the

IFRF furnace, and a maximum of 80% was attained in

the B&W Small Boiler Simulator.

3.7.2. NOx

In the United States, the reduction in NOx formation

is an important driver for research on oxy-fuel

combustion [53]. Government regulations are continu-

ally restricting the allowable level of emissions. If

implemented, the Clear Skies Act would impose more

stringent NOx emission restrictions on power stations in

the United States; in 2008, a cap of 0.17 lb/MM.Btus

and in 2018, a cap of 0.14 lb/MM.Btus is required, on

average for power generators [54]. In 2000, emission

rates of 0.40 lb/MM.Btus were required. Several studies

B.J.P. Buhre et al. / Progress in Energy and Combustion Science 31 (2005) 283–307294

have indicated a significant reduction in NOx emission

resulting from oxy-fuel technology is possible,

suggesting oxy-fuel is a potential technology that

could achieve the required future emission reductions.

During oxy-fuel combustion, the amount of NOx

exhausted from the system can be reduced to less than

about one-third of that with combustion in air [17,37].

The NOx reduction is thought to be the result of several

potential mechanisms [55]:

(1) Decrease thermal NOx due to the very low

concentration of N2 from air in the combustor,

(2) The reduction of recycled NOx in the volatile matter

release section,

(3) Reburning; the interactions between recycled NOx

and fuel-N and hydrocarbons released from coal

may further decrease NOx formation.

Okazaki and Ando used a bench-scale reactor to

examine the effects of the latter two factors during oxy-

fuel combustion with an O2 concentration of 21% (i.e.

recycling ratio as high as 80%) at a maximum flame

temperature of 1450 K [55]. They concluded that the

reduction of recycled NOx is the dominant mechanism

for the reduction in NOx emissions. They estimated that

more than 50% of the recycled NOx was reduced when

80% of the flue is recycled.

Hu and co-workers studied the reduction of recycled-

NOx during oxy-fuel combustion at low recycle ratios

(i.e. high O2 concentration) ranging from 0 to 0.4 [56]. It

was found that the reduction efficiency of recycled-NO

increases with increasing fuel equivalence ratio ((Fuel/

Oxidiser)/(Fuel/Oxidiser)Stoic) and recycling ratio. They

also observed that the reduction efficiency varied from

about 10% at a fuel equivalence ratio less than 0.5 to

nearly 80% at a fuel equivalence ratio of 1.4. The NO2

recycle was found to follow similar trends to the NO

recycle.

Hu also studied the effect of coal properties on the

recycled-NOx reduction [57]. The relative release rate of

nitrogen to volatile matter and the ratio of volatile

nitrogen to char nitrogen are critical in predicting the

emissions of NOx especially in fuel lean environments.

They also investigated the effects of the O2 concen-

tration and gas temperature on NOx emissions finding

that NOx produced per gram of coal fed decreased with

increasing equivalence ratio but for the same equivance

ratio and low oxygen concentrations (i.e. high recycle

ratios) the NOx produced was lower [52]. Increasing the

gas temperature by 400 K at an equivalence ratio of 1,

doubled the NOx produced per kg of coal fed, at all

oxygen concentrations tested. At an oxygen

concentration of 20% in the gas stream and increasing

the gas temperature and decreasing the equivalence

ratio, the NOx produced per kg of coal increased

dramatically (eight times).

It should be mentioned that the above discussions on

the reduction of NOx emission referred to the emission

amount, e.g. mass per unit energy produced from coal

used by Croiset and Thambimuthu [37] or mass per kg

of coal fed. The emission concentration of NO2 (in ppm)

may be higher compared to air combustion due to the

recycle of NO2 in the recycled flue gas, the smaller

amount of flue gas produced on oxy-fuel combustion

and the lower efficiency of oxy-fuel combustion due to

the associated energy requirements of the oxygen plant

and compression unit operations.

3.7.3. SO2

It has been found that oxy-fuel combustion can

decrease the SO2 emissions compared to that in air

combustion [37,52]. Croiset and Thambimuthu

observed that the conversion of coal sulphur to SO2

decreased from 91% for the air case to about 64% during

oxy-fuel combustion. The reason they suggested is that

high SO3 concentrations in the flue gas during oxy-fuel

combustion can result in sulphur retention by ash or

deposits in the furnace. SO2 concentration from oxy-fuel

combustion is known to be higher than that from air

combustion due to flue gas recirculation [36].

Contrary to experimental observations, thermodyn-

amic modelling has suggested that SOx emissions would

be unaffected during oxy-fuel combustion, being

governed only by oxygen concentration [58]. As

thermodynamic calculations assume equilibrium is

established, the conflicting results of these studies

suggest that the formation of SOx in either oxy-fuel

combustion or air combustion has not reached equili-

brium and is governed by rate limitations.

Potential corrosion of the furnace and CO2 transpor-

tation systems due to high SO2 concentrations in the flue

gas could result in the need for desulphurization of the

recycled flue gas for oxy-fuel combustion [18].

Liu et al studied in-furnace desulphurization during

oxy-fuel combustion, indicating a significant increase of

the desulphurization efficiency to about four to six times

as high as that of conventional air combustion [59,60].

This was attributed to longer residence times for

desulphurization, higher SO2 concentrations in the flue

gas and the inhibition of CaSO4 decomposition in the

high SO2 concentrations. They also observed that

limestone (used for sulphur absorption) displayed a

more porous structure as a result of the CO2 presence in

the gas during oxy-fuel combustion, resulting in direct

B.J.P. Buhre et al. / Progress in Energy and Combustion Science 31 (2005) 283–307 295

sulfation of sulphur onto the limestone, enabling better

sorbent utilization than in air combustion [59].

3.7.4. Submicron ash particles

A significant proportion of the submicron ash

generated during coal combustion is believed to be the

result of the vaporisation of refractory oxides [61,62].

These oxides are formed by the reduction of the oxides

to monoxides (e.g. SiO2(s)CCO(g)ZSiO(g)CCO2(g))

which are transported away from the burning particle.

As the monoxides diffuse away from the particle and

encounter oxygen, they re-oxidize to form a fume. The

reducing reactions occur in the locally reducing

environment inside burning char particles.

Krishnamoorthy and Veranth used a detailed char

particle combustion model to study the effect of bulk

gas composition (e.g. CO2 concentration) on CO/CO2

ratio inside a burning char particle [28]. They

indicated that increasing CO2 in the bulk gas

significantly changed the CO/CO2 ratio in the particle

which could affect the vaporization of refractory

oxides, as the concentration of the reducing gas

inside the particle increases.

3.7.5. Trace elements

Using F*A*C*T to assess the emissions of coal

combustion in O2/CO2, Zheng and Furimsky concluded

that the combustion medium had little effect on the

amount and type of the Hg-, Cd-, As-, and Se-containing

emissions in the vapour phase [58]. However, the gas-

phase concentrations of volatile constituents such as

mercury, selenium, and possibly arsenic are expected to

be higher for combustion in an O2/CO2 mixture than in

air. This results because the recycle stream contains

elevated concentrations of these species compared to

air. It appears that Zheng and Furimsky did not include

such elevated trace elements in the feed gas composition

for their calculations of combustion in a predominantly

CO2 environment.

3.8. Full scale techno-economic evaluations

Published studies to evaluate and assess full-scale

applications of oxy-fuel combustion are listed in

Table 3. These studies commonly provide technological

and economical assessments of oxy-fuel technology.

Most studies were based on a comparison of oxy-fuel

technology with air combustion and Mono-Ethanol-

Amine (MEA)/Methyl Diethanol-Amine (MDEA) CO2

scrubbing. The comparisons vary significantly in

presented costs, as the costs vary between different

countries (legislation, policies), and the basis of their

calculations (costs presented as cost per tonne of CO2

were avoided, or whether CO2 sequestration is

considered at all). As there has been little commercial

experience of gas compression of this magnitude, the

cost and efficiency penalties must be considered

uncertain. Sequestration (storage) of CO2 is even less

predictable as there has been no adequate large scale

demonstration to date. A description of publications on

the economic assessment of oxy-fuel combustion

technology follows.

Ishikawajima-Harima Heavy Industries Co (IHI) has

evaluated what they call ‘CO2 recovery type’ pf

combustion based on oxy-fuel combustion technology

[21]. The flowsheet configuration is provided in Fig. 2

with recycling of cold flue gas with:

† An ESP used for ash removal prior to the cold gas

recycle,

† A fabric filter used for gas cleaning prior to CO2

compression,

† The recycled flue gas is preheated by the flue gas in a

regenerative heat exchanger.

The study indicates that a compact boiler can be used

and that removal of NOx and SOx is not necessary. The

study also concluded that the optimum O2 level was

97.5% in the oxidant, based on minimising CO2

compression and liquefaction power. The efficiency

loss was approximately 9% for the energy required for

the Air Separation Unit (ASU) and for CO2 com-

pression, but the capital and operation cost was

substantially less than that for a standard pf plant with

amine absorption for CO2 recovery.

Chalmers University has evaluated the retrofit of an

865 MWe lignite fired power plant in Germany [63,64].

In the study covered by several theses of Chalmers

University, a cryogenic air separation unit was

integrated into the power plant to produce the oxygen

required for combustion [15,65,66]. The oxy-fuel

combustion retrofit and CO2 recovery decreased the

power output and the net electricity efficiency from

865.0 MW and 42.6% to 623.0 MW and 30.7%,

respectively. However, with all identified optimisation

possibilities in the whole system, the power output and

the efficiency increases to 34.3% and 696.7 MW,

respectively. The overall investment cost for the plant

was estimated to be similar as that for the air fired case

[65]. The reason for this similarity is that no

desulphurizing equipment is needed, but instead an

ASU and a flue gas treatment system are required for the

oxy-fuel combustion technology, and the costs for

Table 3

Summary of full-scale technology evaluations

Organisation Oxy-fuel combus-

tion application

Focus of study System features Techno-economic performance Reference

IHI, Japan 1000 MW super-

critical pulverised

coal-fired power

plant

Evaluating the thermal efficiency and

economy of a CO2 recovery power plant

by burning pulverised coal in O2/CO2

Oxygen generation: a cryogenic ASU

with a optimum oxygen purity of 97.5%

Recycle system: wet recycling used

with the recycling position after pollu-

tant controls

Pollutant controls: no DeNOx and no

DeSOx

Flue gas treatment: a filter for further

gas clean, a gas pre-cooler, and a

compressor

CO2 recovery and sequestration: O90%, direct underground deposal

Net electricity efficiency: 29.1%, while

those of conventional ones with and

without MEA scrubbing are 26.0 and

39.6%, respectively

Annual cost: 3.8 billion yen compared

to 11.3 billion yen of air-firing with

MEA

[21]

Air liquide Pulverised coal-

fired boilers (plant

sizes of 30, 100,

200, 500 MW) of

retrofitted or full

oxygen-fired

Comparing the capital and operating

costs of oxygen-fired pulverised coal

boilers for pollutant controls to the costs

of conventional air-fired boilers

Recycle system: flue gas recycled

before pollutant controls

Pollutant controls: no DeNOx, Hg

remoral, FGD

Flue gas treatment: not included

CO2 recovery and sequestration: not

analysed

Total annual cost is comparable to that

of conventional air-fired one, cheaper

for plants up to 200 MW

[19,75]

Chalmers Univer-

sity and Vattenfall

AB, Sweden

VEAG

2!933 MW

lignite-fired power

plant, Lippendorf,

Germany

Evaluating the overall process of an

O2/CO2 power plant to find options for

energy optimisation

Oxygen generation: a cryogenic ASU

with a oxygen purity of 95%

Recycle system: flue gas recycled from

the boiler between economiser and air

heater

Pollutant controls: no DeSOx

Flue gas treatment: a condenser, com-

pressors, a gas hydration unit, non-

condensable gas removal unit

Net electricity efficiency: 34.3 versus

42.6% for conventional air-fired one

Investment cost of the power plant is

same as that of conventional one

[15,63,65,66]

ALSTOM et al.,

USA

AEP’s 450 MW

Conesville Unit 5,

Conesville, Ohio

Evaluating the technical performance of

alternate CO2-capture and sequestration

technologies for an existing coal-fired

power plant

Oxygen generation: a cryogenic ASU

with a oxygen purity of 99%

Recycle system: about 2/3 flue gas

recycled after pollutant controls and a

gas cooler

Pollutant controls: FGD and no DeNOx

Flue gas treatment: a gas cooler, a CO2

compression and liquefaction system

CO2 recovery and sequestration: 94%

of CO2 recovery and 97.8% CO2

concentration

Net electricity efficiency: 23%, while

those of conventional ones with and

without MEA scrubbing are 21 and

35%, respectively

[7]

B.J.P

.B

uh

reet

al.

/P

rog

ressin

En

ergy

an

dC

om

bu

stion

Scien

ce3

1(2

00

5)

28

3–

30

72

96

ANL, USA Using ASPEN Plus model for develop-

ing a system, to characterise mass and

energy flows in the system and to assess

the costs of equipments and operation

Evaluating the fate of sulphur in the gas

path and the performance of sulphur

removal

Oxygen generation: a cryogenic ASU

with a oxygen purity of 99%

Wet recycle system

Pollutant controls: FGD and no DeNOx

Flue gas treatment: a gas dryer, non-

condensable gas removal system, a CO2

compression system

Supercritical CO2 pipeline delivery to

oil field

The total cost for pf plant with a retrofit

recycle was 69.9 US$/tonne CO2, the

cheapest among the studies fossil- and

non-fossil based energy cycles.

[18]

CANMET, Canada A typical 400 MW

pulverised coal

fired power plant

Assessing the techno-economic per-

formance of CO2 capture from an

existing power plant with MEA scrub-

bing and O2/CO2 recycle combustion

Oxygen generation: a cryogenic ASU

with a oxygen purity of 99.5%

Dry gas recycling

Flue gas treatment: a compressor and a

low temperature flash (LTF) unit to

capture CO2 in flue gas

CO2 recovery and sequestration: CO2

concentration is 98%

CO2 capture cost of O2/RFG is 35 US$/

tonne CO2 avoided (equivalent to 3.

3 cent/kWh), lower than 53 US$/tonne

CO2 avoided (equivalent to 3.3 cent/

kWh) of air combustion with MEA

scrubbing

[8,70]

MITI, Japan 600 MW power

plants

Assessing the performance of various

combinations of power generation, CO2

capture and sequestration technologies

for fossil power plants

Power generation: LNG C/C, Oxy-fuel

USC pf, O2-blown IGCC, air-blown

IGCC, RMF

CO2 capture: O2/CO2 combustion,

chemical absorptions MEA or MDEA

and physical absorptions SELEXOL or

PSA

CO2 sequestration: five options of

transportations and storage (three deep

sea injections and two underground

injections)

For oxy-fuel SUC pf with CO2 seques-

tration, the values are 22.5–31.6% and

1.7–2.1 times, respectively

[76]

BHP, Australia Assessing the costs, efficiency and CO2

abatement costs of various power

generation technologies

Power generation: SC pf, USC pf,

NGCC, Direct fired coal CC, IGCC,

wind.

CO2 capture for oxy-fuel USC pf

reduces the overall efficiency by about

9%, and reduces 18–20% sent out

electricity

Currently O2 USC pf would be the

lowest carbon capture and storage cost

Currently, O2 USC pf gives a CO2

abatement cost at 28–31% A$/tonne

CO2

[41]

Canadian clean

power coalition

(CCPC), Canada

New ‘Greenfield’

sites and three

retrofits

Assessing the most economic CO2

capture technology

Retrofit: Amine scrubbing vs oxy-fuel

combustion under future air emission

restrictions

Air-firing should be possible for the

oxy-fuel plant

No net loss of power sent out; auxiliary

power is supplied by new plant using

same technology as original plant

New plants (IGCC) are cheaper than

retrofits

Amine was cheaper than oxy-fuel; full

airfiring capacity results in large gas

stream and gas cleanup equipment No

details provided except in confidential

reports

[77,78]

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.B

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reet

al.

/P

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En

ergy

an

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1(2

00

5)

28

3–

30

72

97

B.J.P. Buhre et al. / Progress in Energy and Combustion Science 31 (2005) 283–307298

these balance each other. Vattenfall is currently

pursuing oxy-fuel combustion as a highly interesting

option for lignite-based power generation with CO2

capture, as indicated in their later studies and the active

role of Vattenfall as coordinator for the ongoing EU

project ENCAP (ENhanced CAPture of CO2) [67].

ALSTOM together with ABB Lummus Global Inc,

American Electric Power, National Energy Technology

Laboratory and Ohio Coal Development Office con-

ducted a comprehensive study to evaluate the technical

feasibility and cost of three CO2 capture and sequestra-

tion technologies applied to an existing 450 MW US

bituminous coal fired power plant [7,68,69]. The

comparison comprised the following options:

(1) Air combustion and CO2 separation with MEA

absorption,

(2) Oxy-fuel combustion,

(3) Air combustion with CO2 separation by MEA/M-

DEA absorption.

ALSTOM developed a computer simulation of oxy-

fuel combustion and used this to evaluate technical and

economic issues, including boiler performance and plant

efficiency, heat transfer characteristics, etc. The flow

diagram of oxygen-firing technology is shown in Fig. 5,

and is similar to that considered by IHI. The main

difference is that the ALSTOM flowsheet contains a flue

gas desulphurizer (FGD) and gas cooler before the

recycle stream, while the IHI flowsheet did not consider

an FGD and the gas cooler was situated after the

recycle point. Additionally, the location of the feedwater

pre-heater and the oxygen heater is somewhat different

in the two configurations.

ESP

ASU

OxygenPre-heater

Gas

-Gas

Hea

ter

GRF/FDFPrimFan

Mill

Boiler

Oxygen

ID Fan

Air Nitroge

Fig. 5. Simplified gas side process flow diagram for CO2 separ

The main findings of the ALSTOM study can be

summarised as follows:

† Technically, the oxy-fuel combustion for CO2

capture is comparable to that of air-firing with

MEA and MEA/MDEA for CO2 capture. For an oxy-

fuel combustion retrofit, no major technical barriers

have been observed and no major boiler system

modifications are necessary except those controlling

air in-leakage.

† The boiler efficiency increases from 88.13% for

conventional air firing to 90.47% during oxy-fuel

combustion, based on the same coal feed rate, due to

the addition of an oxygen heater and a parallel

feedwater heater. The plant thermal efficiency

decreases from 35% in the case of normal air-firing

to 23% in the case of oxy-fuel combustion. This is

mainly the result of the energy requirements of the

air separation unit and the CO2 compression and

liquefaction system. The efficiencies of the air-fired

plants with MEA and MEA/MDEA scrubbing are

comparable with values of 21 and 22.9%, respect-

ively.

† For the oxy-fuel combustion case, with two thirds

of the flue gas recycled, the heat transfer in the

retrofitted furnace (referred to the radiation heat

transfer) increases by amounts in the range of 6%

for upper furnace wall to 13% for superheater

panels, while the heat transfer in the convection

pass decreases in the range of 1% for economiser

to 8% for low temperature superheater, compared

to an air fired furnace with the same coal

feed rate.

FGD System

Stack

Feed water heater

ary

Direct ContactGas Cooler

BoosterFan

CO2compression& liquefaction

system

Lime FGD Solids

n

ation with oxygen firing adapted from Nsakala et al. [7].

B.J.P. Buhre et al. / Progress in Energy and Combustion Science 31 (2005) 283–307 299

† The CO2 recovery reaches about 94% during oxy-

fuel combustion, comparable to the values of 96

and 91% of the air-fired systems with MEA and

MEA/MDEA absorptions, respectively.

Argonne National Laboratory used ASPEN Plus to

develop and model a system of oxy-fuel combustion and

CO2 sequestration for EOR [18]. The objective of the

study was to characterise mass and energy flows in

sufficient detail that changes in coal composition, O2

purity, recycle strategy and process equipment effec-

tiveness would be reflected in product composition,

power output, and residual emissions. The model also

assessed the economical aspects of equipment costs and

operation of the system. The system studied was the

same as that assessed by ALSTOM [7]. The reported

results are:

† The total cost for pf plant with a retrofit recycle was

69.9 US$/tonne CO2, the cheapest among the studies

fossil- and non-fossil based energy cycles.

† The fate of sulphur in the gas path and the

performance of sulphur removal were evaluated.

The SO2 concentration buildup in the flue gas system

increases with the fraction of uncleaned flue gas in

the total gas recirculation, which could result in

corrosion issues, an issue earlier indicated by Takano

and co-workers [32]. Table 4 shows the typical

build-up of sulphur in the flue gas as a result of the

recirculation.

CANMET Energy Technology, a Canadian con-

sortium, assessed the techno-economics of two CO2

capture technologies for retrofitting a typical 400 MW

pulverised coal fired power plant [8,70,71]. The two

options considered were conventional air combustion

with flue gas scrubbing using MEA and oxy-fuel

Table 4

Example of the effect of recycle strategy on SO2 concentration in the

flue gas, based on 1000 ppmv without recycle [18]

Fraction of total flue gas

recycled

Sulphur concentration in flue

gas (ppmv)

0.7 3110

0.6 2370

0.5 1920

0.4 1650

0.3 1390

0.2 1230

0.1 1080

0 1000

combustion technology. Both were equipped with a

low temperature flash (LTF) unit for CO2 compression.

Considering the significant energy needed for CO2

separation process, supplemental energy generated by a

natural gas turbine combined recycle was included to

maintain its original output to the grid, while CO2 from

natural gas was not captured. The energy requirements

for these studies were obtained by modelling the

processes using HYSYS [47,72]. Later studies from

this group have addressed the issue of unit de-rating in

more detail and provided some integrated solutions [73].

The results obtained from this study were compared

with those of two similar studies [18,74]. The

conclusions are:

† Oxy-fuel combustion is less expensive for retro-

fitting than the other considered options. The CO2

capture costs were 55 US$/tonne CO2 (equivalent

to 3.3 US cents/kWh) for the case of air combus-

tion with MEA scrubbing, and 35 US$/tonne CO2

(2.4 US cents/kWh) for the case of the oxy-fuel

combustion. The capture costs represent an

approximate increase of 20–30% in current

electricity prices. The results are similar to those

of the other two studies (this is also indicated in

Figs. 6 and 7).

† 74% of the original CO2 emissions can be avoided

using oxy-fuel combustion with a LTF, while 65%

can be avoided by air combustion with MEA

scrubbing. The difference arises because more

natural gas was consumed for generating the

supplemental power for the air firing power plant.

† The sensitivity analysis indicated that a break-

through in oxygen separation technology will have

the greatest impact on reducing CO2 capture costs

using oxy-fuel combustion.

0

10

20

30

40

50

60

70

(Singh et al, 2001)400 MW

(Nsakala et al, 2001)450 MW

(Simbeck, 2001)300 MW

Tot

al C

O2

capt

ure

cost

,U

S$/

tonn

e C

O2

avoi

ded Oxyfuel Air-fired, MEA

35

55

42

53

3843

Fig. 6. Total CO2 capture cost of different CO2 capture technologies

by several studies, expressed as US$/tonne of CO2 avoided (after [8]).

0

200

400

600

800

1000

1200

1400

(Singh et al, 2001)400 MW

(Nsakala et al, 2001)450 MW

(Simbeck, 2001)300 MW

Cap

ital C

ost,

US

$/kW

Oxyfuel Air-fired, MEA

791 736823

1128

930802

Fig. 7. Capital cost for CO2 capture, compared to air firing with MEA

scrubbing, expressed in US$/kW (after [8]).

B.J.P. Buhre et al. / Progress in Energy and Combustion Science 31 (2005) 283–307300

Air Liquide investigated the capital and operating

costs associated with pollution control technology of

flue gas (without considering CO2 capture) from a

pulverised coal fired boiler [19,75]. A multi-pollutant

control system was considered including a wet-FGD for

SOx control, SCR for NOx control, activated carbon

filter bed for mercury capture, and an ESP for fly ash

removal. The study compared the costs of the emission

controls of an oxygen-fired boiler with those of a

conventional air-fired unit, considering both operating

and installation costs. The conclusions are:

† The total annual costs of oxy-fuel combustion plants

(retrofitted and new full oxygen fired) are compar-

able to those of conventional plants, as indicated in

Fig. 8.

† The retrofitted oxy-fuel combustion power plants are

more economical at smaller sizes (up to 200 MW)

than the air-fired power plants.

† The new, fully oxy-fuel plants are less costly than

both the conventional and retrofitted oxy-fuel plants.

The above studies evaluated the techno-economic

performance of oxy-fuel pf combustion and CO2

recovery/capture by comparing the technology with

0

20

40

60

80

100

120

500 MW 200 MW 100 MW 30 MW

Tot

al C

osts

(%

of a

ir-fir

ed c

ase)

Air-fired

Retrofit

Retrofit; No SCR

New; No SCR

Fig. 8. Total annual costs of air- and oxygen-fired plants. The absolute

costs of air-fired plants are: 15.7, 33.1, 53.2, and 116.3 US$ MM for

power plants of 30, 100, 200 and 500 MW, respectively. Adapted

from [75].

conventional air-firing technology and amine CO2

scrubbing. Other studies have assessed the performance

of various power generation and CO2 capture/sequestra-

tion technologies, including oxy-fuel combustion in

ultra-supercritical boilers and IGCC.

Akai and co-workers assessed the performance of

various combinations of power generation, CO2 capture

and sequestration technologies for a 600 MW power

plant [76]. The power generation technologies included

LNG combined cycles, ultrasupercritical pf combustion,

O2-blown IGCC, air-blown IGCC, and reformed

methanol-fired combined cycles. The CO2 capture

technologies include oxy-fuel combustion and chemical

absorptions using MEA/MDEA. The sequestration

technologies included long distance transportation and

deep sea or underground injection. The main con-

clusions were as follows:

† Addition of the CO2 separation/recovery process

decreases the power plant efficiency by values in the

range of 9–27% compared to those of the power plants

without CO2 capture and sequestration, and raises the

power generation cost by a factor of 1.2–1.5.

† Addition of the CO2 capture and sequestration lowers

the power generation efficiency by values in the range

of 12.9–32.8%, and increases the power generation

cost by a factor of 1.3–2.1.

† The relative efficiency decreases for ultrasupercritical

pf oxy-fuel combustion vary from 22.5 to 31.6% (i.e.

power generation efficiency is 28.4–31.7% compared

to 40.9% for non-CO2 capture and sequestration case)

and increases power generation costs by a factor of

1.7–2.1.

The Canadian Clean Power Coalition (CCPC) has

evaluated different options for CO2 extraction from

existing and new coal fired power plants in Canada [77,

78]. This study indicated higher costs for oxy-fuel

combustion compared to amine scrubbing. The papers

are summary reports of the studies done for the

consortium, and the actual report is confidential to the

partners. The report indicated that the oxy-fuel option

was the highest cost option, but that ‘substantial

improvements could be made to the design adopted in

the CCPC studies’ [77]. The plants using oxy-fuel com-

bustion were required to maintain full air firing capacity,

which resulted in high flue gas flow rates and a possible

over-dimensioning of the flue gas cleanup equipment.

A recent CCSD report by BHP Billiton provides a

comparative assessment of electricity production

options for Australia, including projections to 2030

[41]. These options include oxy-fuel combustion with

B.J.P. Buhre et al. / Progress in Energy and Combustion Science 31 (2005) 283–307 301

95% CO2 capture in an ultra-supercritical pf fired boiler.

The technology combinations evaluated include:

1 Incremental developments in pf and gas fired boilers,

2 Integrated gasification combined cycle gas turbine

(IGCC),

3 Underground coal gasification (UCG),

4 Direct fired coal combined cycle (DFC-CC),

5 Oxy-fuel combustion with CO2 capture,

6 IGCC with CO2 capture.

The report quantifies the effect of CO2 capture on

efficiency and assesses the cost of CO2 abatement.

Current and projected costs and efficiencies of

technologies are listed in Table 5 and the electricity

costs are shown in detail in Fig. 9. Estimates of the

cost of CO2 abatement using different technologies

are provided in Table 6. The main conclusions of the

assessment are:

† CO2 capture for oxy-fuel combustion in ultra-

supercritical boilers reduces the overall thermal

efficiency by approximately 9%, due to the

parasitic losses for oxygen production and flue

gas compression/liquefaction.

† CO2 capture and compression reduces the sent out

electricity by 18–20% for oxy-fuel combustion in

ultra-supercritical boilers (on a relative basis).

Table 5

Current and projected costs and efficiencies of technologies from [41]

Technology 2002

Capital cost

(A$M/MW)

Ef

Supercritical pf (SC)a 1151 41

Natural gas combined cycle (NGCC) 825 53

Ultrasupercritical pf (USC) 1210 43

Oxy-fuel combustion ultrasupercritical pf with

95% carbon capture and sequestration (O2-USC-

95% CCS)b

1868 34

Direct fired coal combined cycle (DFC-CC) 926 49

Integrated gasification combined cycle (IGCC) 1584 43

Oxygen-fired integrated gasification combined

cycle with 25% carbon capture and sequestration

(O2-IGCC-25% CCS)b

1839 39

Oxygen-fired integrated gasification combined

cycle with 75% carbon capture and sequestration

(O2-IGCC-75% CCS)b

2453 33

Wind (based on peak capacity factor)c 1700 –

a Based on A$2002.b Excludes CO2 transmission and storage.c Excludes effects of low capacity factor (25–30% for wind) and any energ

† Currently and in the near future, oxy-fuel combustion

in ultra-supercritical boilers with 95% CO2 seques-

tration would be the lowest cost technology for carbon

capture and storage at A$28–31/tonne CO2.

† Oxygen ultra-supercritical is recommended as having

good economics and, while not yet demonstrated, is

considered to be achievable.

3.9. Summary of techno-economic assessments

From the techno-economic assessment of the oxy-

fuel pulverised coal power plants, the following general

conclusions can be summarised as:

† Oxy-fuel combustion pulverised coal combustion is

technically and economically feasible for retrofitting

existing power plants.

† Oxy-fuel combustion for CO2 recovery and seques-

tration is a competitive power generation technology.

† Oxy-fuel combustion is associated with cost and

efficiency penalties. Generally CO2 capture reduces

the net electricity efficiency by about 10% compared

to the conventional air firing power plants without

CO2 capture. However, the efficiency and costs of

oxy-fuel combustion are less or comparable if the CO2

capture (e.g. MEA absorption) is also included in the

conventional power plants.

2010 2030

f. (%) Capital cost

(A$M/MW)

Eff. (%) Capital cost

(A$M/MW)

Eff. (%)

1062 43 960 45

679 56 614 65

1117 45 1010 52

1589 37 1438 44

762 52 689 60

1172 48 884 50

1360 45 1026 60

1814 40 1369 44

1458 – 1014 –

y storage. These factors increase the capital cost/MW by 800–1000%.

0

10

20

30

40

50

60

70

SC

NGCCUSC

O2 USC-9

5% C

CS

DFC-CC

IGCC

O2-IG

CC-25%

MEA-C

CS

O2-IG

CC-75%

MEA-C

CS

O2-IG

CC-75%

SX-C

CS

Ele

ctric

ity C

osts

(A

$/M

Wh)

Capital Service

CO2 Disposal

Other

Fuel

Fig. 9. Cost comparison of power generation technologies suggested

by Cottrell et al. [41].

B.J.P. Buhre et al. / Progress in Energy and Combustion Science 31 (2005) 283–307302

† The most expensive component of the oxy-fuel

combustion system is the air separation unit. Never-

theless, the cost could be balanced by eliminating the

NOx and SOx removal equipment and decreasing the

capitol cost of post-combustion clean up due to the

reduced flue gas volume.

† SOx removal equipment could be optional for oxygen

firing system, which depends on the CO2 storage/u-

sage and whole system costs.

Table 7 provides a summary of the main economic

assessments and their outcomes.

3.10. Technology comparisons

The advantages and disadvantages of oxy-fuel

combustion are summarized in Table 8.

From the technology assessments, the following

process decisions need to be made for an accurate

assessment of oxy-fuel combustion:

Table 6

Costs of CO2 abatement, adapted from [41]

Technology Cost of CO2 abatement 2002

($/tonne CO2)

C

(

IGCC 201 4

DFC-CCGT 76 6

IGCC-25% CCS 95 4

IGCC-75% MEA-CCS 67 4

O2-USC-95% CCS 31 2

NGCC 25 2

USC 28 1

† The oxygen purity from oxygen production.

† The CO2 proportion in the gas product and

associated CO2 recycle ratio.

† Any moisture and ash removal efficiency for the

recycle stream

† The SOx and NOx removal (if any) for the recycle

stream (to control corrosion) and/or prior to CO2

compression.

The technology required depends on the appli-

cations—some reported studies being based on the

need to generate a sequestration-ready CO2 stream,

others to avoid the cost of SO2 and NOx control and also

with regard to CO2 quality. A schematic comparing the

technologies of current pulverised coal combustion (in

Australia), with retrofits of pulverised coal combustion

with amine capture of CO2 and oxy-fuel combustion is

provided in Fig. 10 [79].

The flowsheet for oxy-fuel combustion includes a

heat exchanger to increase the convective heat exchange

surface area and also a fabric filter for the high efficiency

dust removal required by the compressor. The flowsheet

is based on pilot-scale data indicating that relatively

little NOx is formed in oxy-fuel combustion and that

SO2 is removed in the first stage of the compressor/-

cooler. The flowsheet appears to be the most appropriate

for an Australian retrofit. For a new plant the boiler

design would avoid the additional heat exchanger.

4. Research needs

The review indicates that purpose built, retrofit ready

and retrofitted plant can accommodate the technology,

that the economics are favourable, and that the

technology provides a short-term option for near-zero

emission coal technology for power.

There are a number of technology issues to be

resolved and performance characteristics to be estab-

lished by research, these are;

ost of CO2 abatement 2010

$/tonne CO2)

Cost of CO2 abatement 2030

($/tonne CO2)

4 K3

1 34

5 22

2 27

6 21

2 16

8 K7

Table 7

Summary of economic assessments, given generally in terms of cost/tonne of CO2, for PC (pulverised coal) plant (as detailed) typical of country

Plant type PC plant

details

Assessment Result $/tonne CO2 Reference

Retrofit, USA PC with FGD Incremental cost for CCS (capture, compression,

transport and sequestration) for post -PC and post-

IGCC capture

PC with FGD-US$33-72 IGCC-$US21-62 [84]

Retrofit,

Canada

PC with FGD Incremental cost for CCS for post-PC and oxy-fuel PC with FGD-US$55 Oxy-fuel-US$35 [8]

Retrofit, USA PC with ESP Capital and O&M cost of CO2, SO2, NOx and Hg

removal (CO2 removal using MEA)

Oxy-fuel-169-188 US$/kWe, PC with

removal-295 US$/kWe, O&M costs: oxy-

fuel K1⁄2 of MEA costs

[19]

New plant,

USA

PC with

FGD, de-NOx

(SCR) and Hg

removal

Capital and operating cost (without CCS) for

compact oxy-fuel design

Oxy-fuel w85% of air fired PC for

500 MW unit

[34]

New plant,

Australia

No FGD or

de-NOx

Cost of CO2 avoided with CCS, compared to

supercritical pc without CCS

IGCC-A$64 Oxy-fuel-A$29 [41]

New plant,

Japan

PC with FGD

and catalytic

de-NOx

Additional capital and operating cost of oxy-fuel

compared to pc with FGD and catalytic de-NOx and

post-pc capture

Oxy-fuel w30% of post pc capture, with

amine solvents

[6]

B.J.P. Buhre et al. / Progress in Energy and Combustion Science 31 (2005) 283–307 303

4.1. The heat transfer performance of new and

retrofitted plants and the impact of oxygen feed

concentration and CO2 recycle ratio

Calculations suggest that conditions cannot be

established for the same radiative transfer in the boiler

and also convective heat transfer in the convective

passes. The need for plant modifications to avoid down

rating an existing unit when retrofitting of the output

needs to be clarified. The greater radiative absorption of

the high CO2 atmosphere during oxy-fuel combustion

will result in radiative transfer occurring over shorter

distances in the furnace. Local variations in heat

transfer, potentially metal hot spots, and higher gas

temperature gradients may result, requiring more careful

Table 8

List of the advantages and disadvantages of oxy-fuel combustion

Advantages

† Industry is familiar with this type of technology and it potentially

represents a lower commercial and technical risk than for CO2

capture with e.g. coal gasification technology.

† Suitable for near-zero emissions.

† Has potential to be retrofitted to existing plant as either oxy-fuel

with CO2 liquefaction, or as direct flue gas liquefaction.

† Can be implemented in new plant by modifying technology

commonly used in the power industry.

† Could be allowed in new plant design for retrofit at a later time.

† Low NOx emissions relative to conventional PF technology

control of gas flow patterns to maintain gas temperature

uniformity.

4.2. The gas cleaning required

Some reported flow sheets have SO2 scrubbers

included in the CO2 recycle loop or prior to compression.

Both are unlikely to be necessary for applications in

Australia, as the use of low-sulphur coals may avoid

furnace corrosion due to the accumulation of sulphur

gases, and the use of a two stage compressor will allow

removal of sulphur gases prior to the final CO2

compression. Sulphur scrubbing for flue gases potentially

released to atmosphere is not currently required in

Australia, but will be required for overseas applications.

Disadvantages

† Significantly reduced efficiency compared to currently used PF

technology.

† Not demonstrated so there may be possible unforseen technical

problems.

† May require SOx removal.

† Large oxygen separation plant required compared to other

near-zero technologies.

† Oxy-fuel is based on near-zero emissions and electricity economy

and cannot be adapted to the ‘hydrogen economy’.

† There is a lack of information/debate over flue gas liquefaction

(base case), and especially relation to integration with

conventional pf fired boilers with conventional air combustion.

Additionalequipment

FuelAir

Boiler Dust removal CO2/N2

DustRemoval

high Boiler De-NOx CO2 recovery

amine absorption

CO2

N2/H2O

CO2Storage/SequestrationCompressor/Cooler

FuelAir

ASU

Fuel Boiler Dust Removalhigh

H2O/SO2

O2

CO2Storage/Sequestration

Compressor/Cooler

AirHeat

Exchanger

Standard Australian PCF System

PCF+Amine Absorption

Oxy-firing System

De-SOxhigh

η

ηη

Fig. 10. Flowsheets for Australian retrofit options [79].

B.J.P. Buhre et al. / Progress in Energy and Combustion Science 31 (2005) 283–307304

4.3. Assessment of retrofits for electricity cost

and cost of CO2 avoided

Most of the assessments available are for new

plants, as is the detailed assessment relevant to

Australia. Retrofits of existing air fired plant for oxy-

fuel combustion also need to be evaluated for

electricity cost and cost of CO2 avoided, these

being plant specific, and also dependant on the

economic value assigned to the plant considered. The

assessments also considers super critical plants,

however retrofits may use subcritical plants of

lower efficiency, where the relative efficiency penalty

due to the oxygen plant will be greater.

4.4. The combustion of coal in an O2/CO2 atmosphere,

including ignition, burn-out, and emissions

The combustion aspects need clarification and

emission levels require determination, desirably at

pilot-scale, for environmental impact assessments of

technology proposals.

4.5. The development of new, and less expensive, oxygen

generation technology

The oxygen plant is a major cost in oxy-fuel

combustion (as it is in O2-blown IGCC) and results in

an efficiency penalty for electricity generation. Devel-

opments to improve oxygen generation technology

should be continuously reviewed.

5. Conclusions

After initial introduction in 1982, oxy-fuel combus-

tion for pulverised coal combustion was researched as a

means to produce relatively pure CO2 for Enhanced Oil

Recovery. Despite these research efforts, the technology

did not pick up on a large scale for this application.

However, the increase in the awareness of greenhouse

gas emissions into the atmosphere has renewed the

interest in this technology, with a two-fold focus:

† The generation of a relatively pure CO2 for

sequestration,

† The potential to reduce pollutant emissions, in

particular NOx.

Research into oxy-fuel combustion has not been

limited to the development of new plants that have the

advantage of smaller flue gas cleaning equipment, but

has also included retrofits of existing plants, particularly

interesting for decreasing greenhouse gas emissions

from existing power generators.

B.J.P. Buhre et al. / Progress in Energy and Combustion Science 31 (2005) 283–307 305

The renewed interest in oxy-fuel combustion has led to

many laboratory-scale and pilot-scale studies by various

groups that covered many scientific and engineering

fundamental issues on the application of this technology.

The following issues have been identified for oxy-fuel

combustion: (1) Heat transfer, (2) Environmental issues;

gaseous emissions, (3) Ash related issues, and (4)

Combustion; ignition and flame stability.

This review provides a summary of the work done by

the various groups and summarizes their findings for the

four issues identified. Many of the technical issues have

been dealt with in the literature and a general under-

standing of the process has been acquired. Despite these

research efforts, four areas have been identified that

need to be addressed in more detail to obtain a more

fundamental understanding of the changes between oxy-

fuel combustion and conventional air-fired combustion:

† The heat transfer performance of new and retrofitted

plant and the impact of oxygen feed concentration

and CO2 recycle ratio,

† The gas cleaning required,

† Assessment of retrofits for electricity cost and cost of

CO2 avoided,

† The combustion of coal in an O2/CO2 atmosphere,

including ignition, burn-out, and emissions.

The techno-economic studies revealed that oxy-fuel

combustion is a cost-effective method of CO2 capture.

More importantly, the studies indicate that oxy-fuel

combustion is technically feasible with current technol-

ogies, reducing the risks associated with the implemen-

tation of new technologies.

Acknowledgements

The authors wish to acknowledge the financial

support provided by the Cooperative Research Centre

for Coal in Sustainable Development, which is funded in

part by the Cooperative Research Centres Program of

the Commonwealth Government of Australia. The

authors would like to specifically acknowledge the

valuable contributions made to this paper by Dr Louis

Wibberley (CSIRO Energy Technology, Australia), Mr

Keiji Makino (IHI, Japan), Prof. Adel Sarofim (Univer-

sity of Utah, USA), Dr Yewen Tan (CANMET,

Canada), and Prof. Lars Stromberg (Vattenfall, Swe-

den). Working with our colleagues in the Japan/Aus-

tralia Oxy-fuel Feasibility Study, particularly project

leader Dr Chris Spero (CS Energy, Australia), has

provided much stimulation and many insights into the

technology. Preparations for sessions and a panel

session at the 2005 Clearwater Coal Conference with

Dr Ligang Zheng (CANMET, Canada) provided further

insights and information.

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