Thursday, January 23, 2020

Benefits of Using Oxy-fuel Combustion Technology for Coal-fired Power Plant

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.

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 emissions 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-supercritical 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 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]:
  • CO2 capture from plants of conventional pf design by scrubbing of the flue gas
  • IGCC with an air separation unit to provide O2.
  • Oxy-fuel combustion with the oxygen diluted with an external recycle stream to reduce its combustion temperature.
  • 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.
  • 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 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:
Fig. 1. General flow sheet for oxy-fuel combustion.
  • 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 about60% 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 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 sequestration 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 technology are concerned with the application of coal-fired pulverised fuel boilers to produce a CO2 rich stream ready for sequestration. Other studies have considered 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 determine 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 concentration 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 compression for subsequent transportation and storage. In this form oxy-fuel combustion involves modification to familiar pf coal technology to include oxygen separation, 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.

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

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 sequestration 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 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 concentration 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 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 concentration in the gas is elevated (around  30%  by  volume), which increases particle combustion temperature. 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

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 Environmental 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 combustion 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 performance to normal air operation, and also yielded in-flame gas composition trends, combustion performance, flame length and flame stability comparable 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 efficiency 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.
Table 2 Summary of pilot-scale studies

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

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 demonstrate 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 code for future development [38]. The following conclusions were drawn:
Fig. 4. Pilot scale results comparing air and O2 combustion NOx levels (the baseline value in air firing case is 100), adapted from [34].
  • 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 combustion 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 performance and heat transfer patterns.
  • Oxy-fuel combustion achieves clean coal combustion, 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 distributions 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 retrofitting 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].

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. Va´rhegyi 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 (Va´rhegyi 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 concentrations 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 concentration 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 continually 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 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 concentration 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, thermodynamic 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 equilibrium and is governed by rate limitations.

Potential corrosion of the furnace and CO2 transportation 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 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) + CO(g) = SiO(g) + CO2(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 compression, 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 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].

Table 3 Summary of full-scale technology evaluations

ALSTOM together with ABB Lummus Global Inc, American Electric Power, National Energy Technology Laboratory and Ohio Coal Development Office conducted a comprehensive study to evaluate the technical feasibility and cost of three CO2 capture and sequestration 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.

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%, respectively.
  • 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.
  • 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.
Fig. 5. Simplified gas side process flow diagram for CO2 separation with oxygen firing adapted from Nsakala et al. [7].

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 effectiveness 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$/tonne CO2, the cheapest among the studies fossil- and non-fossil based energy cycles.
  • The fate of sulphur in the gas path and the performance of sulphur removal were evaluated. The SO2 concentration buildup in the flue gas system increases with the fraction of uncleaned flue gas in the total gas recirculation, which could result in corrosion issues, an issue earlier indicated by Takano and co-workers [32]. Table 4 shows the typical build-up of sulphur in the flue gas as a result of the recirculation.
CANMET Energy Technology, a Canadian consortium, assessed the techno-economics of two CO2 capture technologies for retrofitting a typical 400 MW pulverised coal fired power plant [8,70,71]. The two options considered were conventional air combustion with flue gas scrubbing using MEA and oxy-fuel combustion technology. Both were equipped with a low temperature flash (LTF) unit for CO2 compression. Considering the significant energy needed for CO2 separation process, supplemental energy generated by a natural gas turbine combined recycle was included to maintain its original output to the grid, while CO2 from natural gas was not captured. The energy requirements for these studies were obtained by modelling the processes using HYSYS [47,72]. Later studies from this group have addressed the issue of unit de-rating in more detail and provided some integrated solutions [73]. The results obtained from this study were compared with those of two similar studies [18,74]. The conclusions are:
  • Oxy-fuel combustion is less expensive for retro- fitting than the other considered options. The CO2 capture costs were 55 US$/tonne CO2 (equivalent  to 3.3 US cents/kWh) for the case of air combustion 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 breakthrough in oxygen separation technology will have the greatest impact on reducing CO2 capture costs using oxy-fuel combustion.
Table 4 Example of the effect of recycle strategy on SO2 concentration in the flue gas, based on 1000 ppmv without recycle [18]

Fig. 6. Total CO2 capture cost of different CO2 capture technologies by several studies, expressed as US$/tonne of CO2 avoided (after [8]).

Fig. 7. Capital cost for CO2 capture, compared to air firing with MEA scrubbing, expressed in US$/kW (after [8]).

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 comparable 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 conventional air-firing technology and amine CO2 scrubbing. Other studies have assessed the performance of various power generation and CO2 capture/sequestration technologies, including oxy-fuel combustion in ultra-supercritical boilers and IGCC.

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].

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 conclusions 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 combustion 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 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).
  • Currently and in the near future, oxy-fuel combustion in ultra-supercritical boilers with 95% CO2 sequestration 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 sequestration 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.
  • The most expensive component of the oxy-fuel combustion system is the air separation unit. Nevertheless, 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/usage and whole system costs.
Table 5 Current and projected costs and efficiencies of technologies from [41]

Fig. 9. Cost comparison of power generation technologies suggested by Cottrell et al. [41].

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:
  • 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 applications—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 established by research, these are;

Table 6 Costs of CO2 abatement, adapted from [41]

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

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 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.

Table 8 List of the advantages and disadvantages of oxy-fuel combustion

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

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. Developments to improve oxygen generation technology should be continuously reviewed.

5. Conclusions

After initial introduction in 1982, oxy-fuel combustion 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.

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 understanding 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 technologies, reducing the risks associated with the implementation of new technologies.

Source: 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

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