Oxy-fuel combustion of solid fuels

Abstract

Oxy-fuel combustion is suggested as one of the possible, promising technologies for capturing CO₂ from power plants. The concept of oxy-fuel combustion is removal of nitrogen from the oxidizer to carry out the combustion process in oxygen and, in most concepts, recycled flue gas to lower the flame temperature. The flue gas produced thus consists primarily of carbon dioxide and water. Much research on the different aspects of an oxy-fuel power plant has been performed during the last decade. Focus has mainly been on retrofits of existing pulverized-coal-fired power plant units. Green-field plants which provide additional options for improvement of process economics are however likewise investigated. Of particular interest is the change of the combustion process induced by the exchange of carbon dioxide and water vapor for nitrogen as diluent. This paper reviews the published knowledge on the oxy-fuel process and focuses particularly on the combustion fundamentals, i.e. flame temperatures and heat transfer, ignition and burnout, emissions, and fly ash characteristics. Knowledge is currently available regarding both an entire oxy-fuel power plant and the combustion fundamentals. However, several questions remain unanswered and more research and pilot plant testing of heat transfer profiles, emission levels, the optimum oxygen excess and inlet oxygen concentration levels, high and low-temperature fire-side corrosion, ash quality, plant operability, and models to predict NO_x and SO₃ formation is required.

Introduction

The world, and especially the developing countries such as China and India, is facing an increasing growth in the demand for electrical power [1], [2]. New power plants are thus being constructed at a considerable rate in order to keep up with this demand [1], [2], [3]. The majority of the recently constructed and planned power plants, on a world-wide basis, are coal-fired [1], [2]. Coal is a cheaper and more abundant resource than other fossil fuels such as oil and natural gas while at the same time being a very reliable fuel for power production [4], [5].

In the developed countries an increasing part of the energy consumption is being produced from renewable sources of energy; wind, biomass, solar, hydro power, etc. [1]. The main purpose of the shift from a fossil fuel based production to renewable energy is to decrease the emission of greenhouse gases. Especially the emission of CO₂ from the combustion of fossil fuels has gained great focus in recent years in connection with the discussions of global warming. Since the beginning of the industrialization in the late part of the 18th century the amount of CO₂ in the atmosphere has increased sharply from about 280 to 380 ppm [6], see Fig. 1.

Table 1 lists the current and projected CO₂ emissions, in Gton carbon per year, from power generation (both electricity and heat) [1]. Both the emissions and the coal share of the emissions are seen to increase toward 2030 for the world as a whole. Even though the CO₂ emissions are seen to increase within Europe the percentage increase is much less pronounced than for the rest of the world and the coal share of the emissions is expected to decrease. Despite the fact that the ultimate goal for most countries is to phase out all fossil fuels in heat and power production as well as in the transport sector, the share of renewable energy sources increases only slowly and the world will depend on fossil fuels for many years to come. A rapid move away from fossil fuels could result in great conflicts concerning water and land use between biomass for energy production, food production, and forestation [7] as well as in serious disruption to the global economy [8]. The latter is mainly caused by the long lifetime of the energy supply infrastructure. In the transitional period, technologies are sought which will enable the continuous usage of fossil fuels but at the same time eliminate the emission of CO₂.

Since power plants constitute large point sources of CO₂ emission the main focus is related to their operation. Currently, several possible technologies are being investigated which will enable the so called Carbon Capture and Storage (CCS) from power plants [5], [8], [9], [10], [11], [12], [13], [14]. Both researchers in universities and other research institutions, most manufacturers of boilers and other power plant related equipment, and many power companies are active. CCS will act as a complimentary technology to the ongoing work related to increasing fuel efficiency and the change toward fuels with lower fossil carbon content, e.g. natural gas and/or biomass. As indicated by the term CCS, the elimination of CO₂ emissions include two consecutive operations:

• Capture of CO₂ from the power plant flue gas

• Storage of the CO₂ (incl. transport to storage site)

The estimated cost of separation, capture, and compression of CO₂ (point 1) from power plants or other point sources accounts for around 75% of the total cost of a geologic sequestration process [11], [15], [16], [17].

The disposal technology should ensure a complete elimination of the CO₂ from the earth's carbon cycle in order to stabilize the CO₂ concentration in the atmosphere. Two types of disposal are defined: sequestration (permanent disposal) or storage (disposal for a significant time period) [7]. These terms are often interchanged in the sense that time periods of more than the order of 10,000 years are considered permanent. Possible storage methods suggested include injection in e.g. depleted oil and gas reservoirs, coal beds, deep saline aquifers, etc. [7], [11], [17], [18], [19], [20], [21], [22], [23], [24]. The estimated storage potential for the suggested options is given in Table 2.

When CO₂ is injected below the caprock in oil and gas reservoirs as well as deep saline aquifers it is first trapped by static and hydrodynamic mechanisms. Secondary trapping mechanisms begin operating over time and act to immobilize the CO₂ in the reservoir, thereby significantly limiting the risk of leakage [7], [15], [24], [25], [26]. This type of storage is considered secure even in the initial injection phase where the secondary trapping mechanisms contribute only minimally [7].

The large storage potential in deep aquifers without structural traps is only obtainable if the traps are not required for secure storage during the initial phases [19]. Even without this storage volume the remaining sites offer storage capability for potentially the next many hundred of years [19], [22], see more below. According to Table 2 the estimated retention time in the underground storage sites is 10⁵–10⁶ years. The retention time for storage in combination with enhanced oil recovery (EOR) differs between authors and ranges from only 10s of years [20], [19] to permanent disposal [7].

Because of the limited retention times and the great risks of explosive release of CO₂ back into the atmosphere and/or an alteration of the ocean chemistry in the near vicinity of the disposal sites [7] ocean disposal is regarded a less attractive storage solution.

A comparison of the estimated CO₂ emissions from power production, Table 1, and the estimated storage capacities in EOR and saline aquifers, Table 2, yields between 75 and 6000 years of storage on a world-wide basis (2.5 Gton C/year stored). This calculation is based on the fact that due to small size and remote location of many utility plants only a limited fraction of these emissions can be captured and stored cost-effectively. Baes et al. [18] estimate this fraction to be around 50%. CCS is generally not anticipated as a permanent solution to the elimination of anthropogenic CO₂ emissions from electricity and heat generation. The lower limit of 75 years of storage capacity should thus be sufficient in order for the industry to change almost entirely toward renewable sources of energy.

The identified technologies for carbon capture can be divided into four main categories [5], [11], [12], [23], [27], [28], [29], [30], described briefly below. Fig. 2 shows the main operations concerned with the post-, pre-, and oxy-fuel combustion technologies.

Post-combustion capture: CO₂ is separated from the flue gas of conventional pulverized-coal-fired power plants. The separation is typically performed via chemical absorption with monoethanolamine (MEA) or a sterically hindered amine (KS-1) [23], [31], [32], [33], [34], [35]. Amine absorption is a proven technology in the process industry [23], [34], [36], [37]. The demonstrated scale of operation is, however, significantly smaller than the typical size of power plants [34] and serious penalties to the plant efficiency exist at the current state of development [5], [8], [12], [16], [34], [38], [39], [40], [41], [42], [43]. The anticipated drop in the net efficiency of the power plant is about 10–14% points [41], [34]. Some current research projects investigate the possibility of developing more efficient absorbents [35]. More on the technology can be seen in [5], [8], [13], [29], [44], [45], [46], [47].

The chilled ammonia process in which an aqueous solution of ammonia constitutes the absorbent has shown promising reductions in energy consumption in laboratory studies, up to 50%, compared to the MEA process [42]. The process benefits from low operating temperatures and precipitation of ammonium bicarbonate (NH₄HCO₃) yielding a higher CO₂ loading of the absorbent.

Retrofit to existing plants for both process types is considered relatively simple since the capture unit can be added downstream of the boiler and flue gas cleaning systems without any significant changes to the original plant [8], [45]. There are, however, strict requirements for removal of SO₂ and NO₂ from the flue gas prior to the CO₂ capture since these components react irreversibly with the absorbent leading to its degradation.

Pre-combustion capture: Also termed fuel decarbonisation. The process is typically suggested to be used in connection with Integrated Gasification Combined Cycle (IGCC) power plants where it is termed IGCC–CCS. Coal gasification is applied to obtain a gas (syngas) containing CO, CO₂, and H₂. The CO is transformed into CO₂ by the water-gas shift reaction and can then be separated from the remaining hydrogen containing gas before this is combusted in a gas turbine. Alternatively, H₂ can be separated from the syngas and the CO combusted in an O₂/CO₂ atmosphere [48]. Some techno-economic calculations [11], [30], [36], [49], [50] show that IGCC has promising process economics and plant efficiency characteristics. However, high capital costs are associated with plant construction and IGCC plants are generally much more complicated systems than suspension-fired boilers [51], [37]. Only few electricity producing IGCC units exist [29], [50], [52], [53], [54], none of which are equipped with CCS. As a consequence of the few plants and limited operating experience along with the highly integrated nature of the plants compared to the more matured, conventional pulverized-coal-fired power plants, the demonstrated availability for IGCC is significantly less (80–85% versus ∼96%, respectively) [5], [30], [37], [50], [52], [55]. IGCC–CCS is not a viable option for retrofit of existing pf plants [30], [51], [56], [57].

Oxy-fuel combustion: By eliminating molecular nitrogen from the combustion medium the flue gas will consist mainly of CO₂ and water. The plant configuration typically suggested involves flue gas recirculation to the burners to control the flame temperature to within the acceptable limits of the boiler materials. Implementation of the oxy-fuel combustion technology in existing pulverized-coal-fired power plants will induce a larger change of the plant configuration when comparing to the post-combustion absorption processes mentioned above. This is mainly due to the fact that the combustion chemistry is altered by substituting recycled flue gas (mainly CO₂ and water) for nitrogen in the oxidizer. Several of the earlier techno-economic assessment studies indicate that oxy-fuel combustion should be the most energy and cost efficient of the carbon capture technologies [9], [16], [38], [58], [59], [60], [61], [62], [63]. This conclusion is mainly based on assumptions of greater boiler efficiency caused by a smaller flue gas volume and the reduced need for flue gas cleaning, i.e. deNO_x and desulphurization, including the derived decrease in capital and operating costs. It is suggested that SO_x and NO_x can be stored along with CO₂ in the geospheric sinks [8], [12], [64], [65]. Typically, no experimental validation of these assumptions has been performed. Whether co-storage of SO_x and NO_x is politically acceptable is, however, questionable.

The main disadvantage of the oxy-fuel combustion technology is the need for almost pure oxygen. The available large-scale technology for air separation is based on cryogenic distillation which will impose a very large energy penalty on the plant [65]. The expected efficiency drop is about 7–11 percent points, or about 15–30% of the generated electricity (net power output), depending on the initial plant efficiency [5], [8], [12], [16], [27], [29], [43], [58], [59], [66], [67], [68], [69].

Emerging technologies: Technologies such as membrane separation, chemical looping combustion, carbonation–calcination cycles, enzyme-based systems, ionic liquids, mineralization, etc. impose the possibility to drastically reduce the cost of electricity and the energy penalty concerned with carbon capture from power plants. The papers by Eide et al. [70], Abu-Khader [28], Hossain and de Lasa [71], and Figueroa et al. [14] provide broad overviews of these technologies and their current state of development.

The choice of technology will depend on several factors. First and foremost the economy and the expected development in plant efficiency is of importance. The maturity, expected availability, operating flexibility, retrofit or green-plant built, local circumstances, utilities preferences, etc. will likewise have to be taken into account. No general acceptance of superiority of one of the presented technologies over the others exists. Several techno-economic studies also indicate that with the current knowledge on the technologies no significant difference in cost within the limits of precision of the applied cost estimates can be determined between amine absorption capture, coal-based IGCC type capture, and oxy-fuel combustion capture [5], [8], [22], [57], [66], [67], [72].

Because of the large changes induced in the power plant by the implementation of oxy-fuel combustion, more research is needed to fully clarify the impacts of the introduction of this technology. Many laboratory scale investigations of the technology have been performed within the last two decades and it is generally accepted that it is possible to burn coal and natural gas in an O₂/CO₂ atmosphere. On the other hand, it is likewise recognized that much work still remains in obtaining sufficient insight into the effects on e.g. emissions, residual products such as fly ash, flue gas cleaning, heat transfer, etc.

In 2005, Wall and coworkers [4] published a literature review on the oxy-fuel combustion technology. The work was updated in the broader CCS review by Wall [5] in 2007. The reviews focused mainly on combustion fundamentals, overviews of research groups and their experimental facilities, techno-economic assessments of the technology, and research needs.

The amount of literature on the oxy-fuel technology has increased drastically over the latter years and significant new information is thus now available. The objective of the present review has been to summarize the current knowledge status on the oxy-fuel combustion technology. The current review has two focuses. (1) The possible advantages and challenges associated with retrofitting of existing pulverized-coal-fired power plants to the oxy-fuel combustion technology as well as considerations regarding green-field plants. (2) The reported results from laboratory- and semi-technical scale experiments regarding the combustion process fundamentals, including the flue gas composition and residual products.