Carbon Capture and Storage Technologies
Carbon Capture and Storage Technologies
Carbon capture and storage also called sequestration (CCS) involves the capture, transport, injection and containment of CO2 (carbon di-oxide) in geological structures such as depleted oil and gas reservoirs, onshore and offshore saline aquifers located deep in the earth’s crust, salt caverns or unmineable coal beds. It is both an approach to enhance production from existing oil and gas operations as well as a means for reducing greenhouse gas (GHG) emissions.
CCS provides an additional alternative in the utilization of fossil-fuel based energy, while providing additional transition time for energy systems to move towards carbon (C) reduced or zero C fuels, such as renewables. There are a number of economic and social benefits of CCS such as (i) reduction of CO2 emissions into the atmosphere, thereby potentially mitigating dangerous climate change, (ii) innovation, access to state-of-the-art technologies, job creation and continued and more sustainable economic development, (iii) secondary revenue stream as emissions of GHGs which are captured and stored can be converted into a tradeable commodity which can be sold on the international market, (iv) reduction in air pollution as potentially harmful pollutants have to be removed to accommodate CO2 capture, and opportunity for enhanced oil and gas recovery.
There are several challenges for the deployment of CCS. Some of the challenges for CCS include (i) reducing the cost of capture and scaling up the capture processes, (ii) identifying the environmental impact of capture, (iii) determining the implications of pressure build-up in a storage formation, (iv) determining where the displaced water goes in a large scale injection and what is the risk to ground water, (v) how to reliably predict the size of the CO2 plume and where it migrates, (vi) how to gain confidence in site selection, (vii) developing cost effective monitoring strategies and detection limits, (viii) engaging finance and insurance industries, (ix) greater regulatory and political certainty at all levels of government, (x) training a workforce for large scale deployment, and (xi) improve public awareness and acceptance.
CCS technologies can be applied to the processes with large-scale emissions, including coal and gas-fired power generation, natural gas processing and fertilizer production, as well as the manufacture of industrial materials such as iron and steel, cement, and pulp and paper etc. The application of CCS technologies to these processes can play a major role in reducing the GHG emissions. Carbon separation and capture technologies have been operational at large-scale in the natural gas and fertilizer industries for decades. The technologies involved in a CCS system have four components namely (i) capture, (ii) transport, (iii) injection, and (iv) monitoring.
Capture is the separation of CO2 from an effluent stream and its compression to a liquid or supercritical state. In most cases today, the resulting CO2 concentration is more than 99 %, though lower concentrations can be acceptable. Capture is normally required to be able to transport and store the CO2 economically.
Transport consists of the conveyance of the CO2 from its source to the storage reservoir. The CO2 is dried and usually compressed before being transported to storage. The compression makes transporting the gas more efficient. CO2 is used commercially in a number of industries, notably the beverage industry, and it has been transported on a large scale for use in recovering oil from reservoirs (enhanced oil recovery). While transport by truck, train, and ship are all possible, transporting large quantities of CO2 is most economically achieved with a pipeline. Major pipeline infrastructure is required to be built to implement CCS on a large scale, and this presents challenges.
Injection consists of the depositing of CO2 into the storage reservoir. The underground storage reservoirs depend on the geological formations. The safety of CO2 storage is of prime importance. Local risks of CO2 storage include (i) CO2 leakage from the storage location, (ii) alteration of ground and drinking water chemistry, and (iii) displacement of potentially hazardous fluids which can be in the reservoir where CO2 is stored. The potential reservoirs include the deep-ocean, ocean sediments, or mineralization (conversion of CO2 to minerals). While some commercial use of CO2 is possible, the amount which can be used compared to the amount of CO2 which is emitted is very small.
Once the CO2 is injected, the storage site is to be monitored to show that the CO2 remains in the reservoir. CO2 is neither toxic nor flammable hence it poses only a minimal environmental, health, and safety risk. The main purpose of monitoring is to make sure that the sequestration operation is effective, meaning that almost all the CO2 stays out of the atmosphere for centuries. The monitoring program begins before injection to establish baseline data. Monitoring during the operational phase is for the recording of the dynamic behaviour of the CO2 as it is injected and within the reservoir. After the injection ceases, the monitoring program is to be designed to ensure that the CO2 storage meets the environmental and safety conditions required. A monitoring program covers three monitoring domains namely (i) the sub-surface domain (the reservoir), (ii) the near-surface domain (shallow zones and soil), and (iii) the atmospheric domain, including wells, faults, and other geological features.
CO2 capture technologies
CO2 can be captured from large stationary emission sources, such as natural gas production facilities (where CO2 is already separated from other gases, as part of the process), fossil fuel fired power stations, iron and steel plants, cement plants and some chemical plants. Unlike the other two components of CCS, transportation and geologic storage, the first component of CCS i.e. CO2 capture is almost entirely technology dependent and is the most expensive step. The technology to capture CO2 from these sources is being adapted from the CO2 separation technology currently used in industries such as the natural gas industry and ammonia (NH3) production and also from the technology used in the air separation industry. New technologies are also being developed.
The major separations technologies for capturing CO2 presently are (i) using a liquid solvent to absorb the CO2 (absorption), (ii) using solid materials to attract the CO2 to the surface, where it becomes separated from other gases (adsorption), and (iii) using membranes to separate the CO2 from the other gases. Other technologies include chemical looping technology (a metal oxide reacts with the fuel, creating metal particles, CO2 and water vapour), low temperature or cryogenic separation processes (which rely on different phase change temperatures for various gases to separate them) and dry regenerable solid processes.
The main competing technologies for CO2 capture from fossil fuel usage are (i) post combustion capture (PCC) from the flue gas of combustion-based plants, (ii) pre combustion capture from the syngas in gasification based plants, and (iii) oxy combustion through the direct combustion of fuel with oxygen. Most of the current combustion processes use air, and the resulting flue gas typically contains low concentrations of CO2 (less than 20 %), and hence, they are more suitable for post-combustion capture technologies
Post combustion capture technologies
Post-combustion capture can be considered a form of flue-gas clean-up. The process is added to the back end of the plant, after the other pollution control systems. Heat integration with the plant is needed for it to be cost-effective .
Electric Power Research Institute (EPRI) has determined in 2009 that there are over 50 post-combustion CO2 capture concepts under development which can be grouped into several physical/chemical process types. These process type groups are (i) chemical absorption, (ii) adsorption, (iii) membranes, (iv) biological, and (v) others. Each of these different groups has different benefits and drawbacks, as well as applicability in different situations. There are considerable developments with respect to first two groups.
Chemical absorption process – It involves one or more reversible chemical reactions between CO2 and an aqueous solution of an absorbent, such as mono-ethanol-amine (MEA)-based solvent, and high performance amines (activated methyldiethanolamine, aMDEA) etc. Upon heating the product, the bond between the absorbent and CO2 can be broken, yielding a stream enriched in CO2. The chemical absorption process for separating CO2 from flue gas is borrowed from the gas processing industry. Amine based processes are being used commercially for the removal of acid gas impurities (CO2 and H2S) from process gas streams. It is hence a proven and well-known technology.
Formula of mono-ethanol-amine is H2NCH2CH2OH. Amine is a group of organic compounds, which can be considered as derived from ammonia (NH3) by replacement of one or more H2 atoms by organic radicals. The substitute groups (R) can be alkyl, aryl or aralykl. When the (R) is an alkyl, the amine is called alkanolamine. In general, it can be considered that a hydroxyl group serves to reduce the vapour pressure and increase the water solubility, while the amino group provides the necessary alkalinity in water solution to absorb the acid gases. Akanolamines remove CO2 from the waste gas streams through an exothermic reaction of CO2 with the amine functionality of the alkanolamine. The amines of commercial interest to capture CO2 are water-soluble.
Amines are classified according to the number of H2 atoms of ammonia which have been replaced by radicals such as (i) primary amine (RNH2) where one H2 atom has been replaced, (ii) secondary amine (R2NH) where two H2 atoms have been replaced, and (iii) tertiary amine (R3N) where all the three H2 atoms have been replaced.
Primary amines include mono-ethanol amine (MEA) and diglycolamine (DGA). MEA has been the traditional solvent of choice for CO2 absorption and acid gas removal in general. MEA is the least expensive of the alkanolamines. Its reaction kinetic is fast and it works well at low pressure, and low concentration of CO2. However, there are several disadvantages.
First, it has a high heat of reaction with CO2, which means high level of energy has to be supplied in the regeneration step. Second, the absorptivity of MEA with CO2 is not high. In the case of primary and secondary alkanolamines the formation of carbamate (RNHCOO-) is the main reaction. The equation for the reaction is CO2 + 2RNH2 = RNHCOO- + RNH3+. In this reaction, two moles of MEA must be used to capture one mole of CO2. Third, the full upper absorption capacity of MEA is not realized in practice due to corrosion problems. The corrosion effect is due to dissolved CO2 and varies with the amines used.
The concentration of MEA in the aqueous phase in the presence of O2 is limited to 20 % by weight. In addition, MEA has the highest vapour pressure of any of the alkanolamines and high solvent carryover can occur during the removal of CO2 from the gas stream and in the regeneration step. To reduce solvent losses, a water wash of the purified gas stream is generally needed. In addition, MEA reacts irreversibly with minor impurities such as COS and CS2 resulting in solvent degradation. Foaming of the absorbing liquid MEA due to the build-up of impurities can also be a concern.
For the present MEA absorber systems, the adsorption and desorption rates are reasonably high, hence good reaction kinetics. However, the packing in the absorber (contactors, to facilitate efficient mass transfer) represents a significant cost, and its energy consumption is also significant for CO2 capture from flue gas. In addition, the stripping temperature is not to be too high (around 150 deg C). Otherwise, dimerization of carbamate can take place, deteriorating the absorption capability of MEA.
Secondary amines include diethanolamine (DEA), di-isopropylamine (DIPA). Secondary amines have advantages over primary amines. Their heat of reaction with CO2 is lower (360 calorie/gram) versus 455 calorie/gram) for primary amines. This means that the secondary amines require less heat in the regeneration step than primary amines. However, it has all the other problems of primary amines.
Tertiary amines include triethanolamine (TEA) and methyl-diethanolamine (MDEA). Tertiary amines react more slowly with CO2 than primary and secondary amines thus require higher circulation rate of liquid to remove CO2 compared to primary and secondary amines. This can be improved through the use of promoters. A major advantage of tertiary amines is their lower heat requirements for CO2 liberation from the CO2 containing solvent. Tertiary amines show a lower tendency to form degradation products in use than primary and secondary amines, and are more easily regenerated. In addition, tertiary amines have lower corrosion rates compared to primary and secondary amines. The main drawback is its reaction rate is too slow.
A typical flowsheet of chemical absorption process for CO2 recovery from flue gas is shown in Fig 1. During the amine absorption operation the waste gas stream and liquid amine solution are contacted by countercurrent flow in an absorption tower (or absorber).
Fig 1 Typical flowsheet of chemical absorption process for CO2 recovery from flue gas
The combustion flue gas coming out of the stack is hot (around 240 deg C), and at atmospheric pressure. Flue gas entering the absorber at high temperatures can lead to solvent degradation and decreased absorption efficiency. The flue gas is to be cooled to a water dew point of 50 deg C, entering the absorber. The absorber usually operates at less than 50 deg C. This is achieved by spraying cooling water in a direct contact cooler.
The CO2 in the flue gas is cooled before entering the absorber where it reacts with ammonium carbonate to form ammonium bicarbonate. NH3 is released as a gas from the solvent solution when the CO2 is absorbed, and the temperature is kept low to minimize this. Gases leaving the absorber pass through a water wash to remove ammonia. The ammonium bicarbonate is heated in the regenerator, separating the CO2. The ammonium carbonate solvent is returned to the absorber. Water and NH3 are removed from the CO2 stream leaving the stripper column.
A blower is installed to give the flue gas enough pressure for it to go through the absorption-desorption system. The waste gas to be scrubbed of the CO2 normally enters the absorber at the bottom, flows up, and leaves at the top, whereas the solvent enters the top of the absorber, flows down (contacting the gas), and emerges at the bottom. Dilution of the circulating amine with water is undertaken to reduce viscosity of the circulating fluid. A higher viscosity fluid requires more power to pump and provide circulation. The liquid amine solution containing the absorbed gas then flows to a regeneration unit (stripper) where it is heated and the acid gases liberated. The solvent regeneration can be carried out at low pressures to enhance desorption of CO2 from the liquid. Some amine solution is typically carried over in the acid gas stream from the regeneration step and the amine solution is recovered using a condenser, in order to avoid excessive solvent losses. The hot lean amine solution then flows through a heat exchanger where it is contacted with the rich amine solution from the contact tower and from there the lean amine solution is returned to the gas contact tower, i.e. absorber.
In case of amine scrubber process, with high performance amines (activated methyldiethanolamine, aMDEA), the complete process (amines and compression to 110 kg/sq cm pressure) require around 1.6 tons of low pressure steam and 160 kWh of power per ton of CO2 captured.
There are some limitations of amine-based processes and which has resulted into technological advances. The amine scrubbing technology in the past has focused on the removal of H2S (hydrogen sulfide) for the natural gas sector. However, the requirements are different for the recovery of CO2 from flue gas. One challenge is the low pressure of the flue gas for absorption of CO2. In addition, impurities in flue gas such as O2, sulphur oxides (SO2,SO3), nitrogen oxides, and particulate matter create special challenges during the separation process.
In summary, the recovery of CO2 from combustion flue gas requires a significant amount of pre-treatment processing in order to avoid any foul-up in the solvent absorption step. This adds to the cost of CO2 capture. However, significant improvements can be made in the solvent absorption process in terms of optimizing the compositions of the absorbing amines and the gas-liquid contactors, in order to manage this.
Physical absorption – For physical absorption, CO2 is physically absorbed in a solvent according to Henry’s Law. The absorption capacity of organic or inorganic solvents for CO2 increases with increasing pressure and with decreasing temperatures. Absorption of CO2 occurs at high partial pressures of CO2 and low temperatures. The solvents are then regenerated by either heating or pressure reduction. The advantage of this method is that it requires relatively little energy; but the CO2 is to be at high partial pressure.
Solid physical adsorption – An adsorption process consists of two major steps namely (i) adsorption, and (ii) desorption. The technical feasibility of a process is dictated by the adsorption step, while the desorption-step controls its economic viability. Adsorption requires a strong affinity between an adsorbent and the component to be removed from a gas mixture (in this case, CO2). However, the stronger the affinity, the more difficult it is to desorb the CO2 and the higher the energy consumed in regenerating the adsorbent for reuse in the next cycle. Hence, the desorption step has to be very carefully balanced against the adsorption step for the overall process to be successful.
Adsorption processes are quite attractive for CO2 capture mechanism, despite their disadvantages such as low capacity of adsorbents and influence of contaminants like SO2, and H2O on the separation process. There are also advantages of this process such as availability, flexibility, fully automated operation of the process and production of high purity product. The separation can be carried out by pressure swing adsorption (PSA) (Fig 2), vacuum-pressure swing adsorption (VPSA), temperature swing adsorption (TSA), pressure-temperature swing adsorption (PTSA), or electric swing adsorption (ESA) processes. The beds of the installation are filled with solid adsorbents. The selectivity depends on difference in adsorption equilibrium or adsorption rates and on the effectiveness (concentration and recovery) has significance on the cycle configuration, adsorption time, pressure of adsorption and desorption, temperature during the process as well as the kind of applied adsorbent.
Fig 2 Pressure swing adsorption process
The main advantage of physical adsorption over chemical absorption is its simple and energy efficient operation and regeneration, which can be achieved with a pressure swing or temperature swing cycle (a swing in pressure or temperature as the process goes through an absorption-desorption cycle in order to achieve separation). Pressure swing adsorption is a commercial process for H2 separation from H2 and CO2 mixtures in H2 production.
There have been significant advances in the development of adsorbents for CO2 removal from flue gases. The primary adsorption material used has been zeolites. Zeolites are more effective for CO2 separation from species which are lesser polar than CO2, so the presence of water and SOx in flue gas streams poses a problem.
New adsorbents have been considered and developed such as carbons, mesoporous silico-aluminates (e.g. zeolitic imidazolate frameworks, ZIFs) and metal organic frameworks (MOFs). Carbon-based adsorbents have the potential to be regenerated by applying electrical voltage, (ESA). New materials being investigated include layered double hydroxide derivatives (LDHs and LDOs). Other advances include functionalising the pores of the adsorbent material by incorporating amines to increase CO2 loading. In this case, the CO2 is separated through a chemisorption process.
New processes are being developed for dealing with high humidity flue gas streams and impurities. These include multilayered adsorbent beds. Multilayered beds enable the use of adsorbents with high CO2 selectivity but they degrade significantly in the presence of water.
Pre-combustion capture technologies
Pre-combustion capture technologies involve removing pollutants and CO2 in the upstream treatment of fossil fuels prior to their combustion for the recovery of heat (via steam), or the production of electric power or H2.
A drawback of post-combustion C capture is the low CO2 concentration in the flue gases which leads to a relatively high energy penalty and high cost of C capture. Pre-combustion strives to reduce these penalties by decarbonizing the process stream rich in CO2 before combustion of the remaining H2 rich fuel. To achieve decarbonization of hydrocarbon fuels, they are first converted into a syngas through the gasification of a fuel with O2 (or air). The syngas is a mixture of CO (carbon monoxide), H2, CO2, and water, depending on the conversion process and the fuel and other components.
The syngas is an intermediate product, which can then be converted to produce (i) H2, (ii) integrated electric power, using the water-gas shift reaction, or (iii) poly generation where a range of energy products can be there including power, heat, H2 and synfuels and other chemicals. The process involved with each of these end energy products is described below.
Production of H2 by methane reforming – The most widely used method today for producing H2 is by catalytic steam reforming of methane (CH4). The reforming reaction of converting CH4 and H2O to CO and H2 is endothermic. The reaction is carried out over a Ni (nickel) catalyst at a high temperature in a direct-fired furnace fuelled by CH4. The catalyst is poisoned by S (sulphur), so any S present in the feed is to be removed. The syngas is in turn passed through a catalytic water-shift converter, where the CO is reacted exothermically with steam to produce H2 and a CO2 by-product. These by-products are then removed from the system. The exhaust gas still contains significant heating value, so it is burned to produce steam or electric power.
Coal gasification – The gasification technologies can produce a gas stream, which is high in CO2 and at moderate pressure. The feed coal is gasified in O2 (or air) to produce a syngas. The syngas is cooled to 200 deg C in syngas coolers generating high- temperature and low-temperature steams. It is then shifted further in a low-temperature water gas shift reactor. The water gas shift reactor is a catalytic reactor where the CO is reacted with steam to produce more H2 and CO2. The gas is then cooled to 35 deg C in preparation for acid gas removal. Roughly 99 % of the H2S is removed from the syngas by physical absorption and converted to elemental sulphur. A PSA unit can be used to separate 85 % of the H2 from the S-free syngas. The H2 leaves at around 60 kg/sq cm and high purity (greater than 99.99 %). The CO2 can be scrubbed from the syngas downstream of the S capture system. The PSA purge gas is compressed and burned in a gas turbine combine cycle to produce electric power.
Gasification technologies are well established for H2 production. Commercial plants have been built and successfully operated to produce H2 for refinery applications and chemical manufacture (e.g. NH3 and methanol production) based on a range of hydrocarbon feedstock.
Integrated electric power – The high H2 content syngas can be burned in a turbo expander to produce electric power in a combined cycle setting. If the syngas is produced using gasification, the scheme is called integrated gasification combined cycle (IGCC). IGCC enables electricity to be generated at high efficiency. Because the gas must be cleaned to prevent damage to the gas turbine, IGCC has very low environmental emissions. In addition, IGCC plants use less water. IGCC is currently being used commercially in many plants globally by gasification of petroleum residuals to provide power, H2, and steam.
The three main types of coal gasifiers are (i) moving bed, (ii) fluidized bed, and (iii) entrained flow. However, most gasifiers considered for CO2 capture are currently based on entrained-flow gasifiers. The commercial application of coal-based IGCC has been limited by its relatively high costs, poor plant availability and competition from pulverized coal generation plants. The cost of CO2 capture in IGCC depends strongly on the type of gasifier.
As mentioned above, to enable CO2 to be captured, the fuel gas is to be fed to a catalytic shift reactor where most of the CO is reacted by steam to give H2 and CO. For the slurry feed gasifier, sufficient steam is already present in the fuel gas from evaporation of the coal slurry water and from the quench cooling of the gasifier product gas. However, for the dry feed gasifier, steam is to be taken from the steam cycle and added to the fuel gas feed to the shift converter.
It is to be noted that IGCC is more expensive for the generation of electricity than conventional pulverized coal combustion, with no CO2 capture in both cases.
Poly-generation – Syngas is a good building block, as it can be used to produce a wide range of energy products. The greatest flexibility offered is poly-generation, in which ‘syngas’ can produce steam, electric power, H2 and chemicals (such as methanol, Fischer-Tropsch liquids) in a single plant complex.
A number of different separation technologies including solvent, adsorbent and membrane technologies can be applied to separate CO2 from the products of gasification.
Absorption – The conventional technology is physical absorption in a two-stage process which removes H2S and then captures CO2. However, the gas needs to be cooled after the water gas shift reaction and then reheated before generating power. This reduces efficiency and increases cost.
Adsorption – Adsorbents can be used to separate CO2 from post-combustion flue gas streams downstream of the water gas shift reaction. Both temperature swing adsorption (TSA) and vacuum/pressure swing adsorption (VSA/PSA) can be used to recover the CO2 from the adsorbent. The CO2 is at low pressure when recovered via VSA/PSA and needs to be compressed for storage.
Membranes – Advanced membrane-based gas separation systems are currently being developed to combine the gas shift reaction and H2 separation in one step. The membrane-based systems employ a water gas shift H2 separation membrane reactor (HSMR) to shift the syngas and extract the H2. The maximum temperature of around 475 deg C ensures fast chemical kinetics and good water gas shift equilibrium performance is obtained by continuous removal of the H2 product.
There are three major classes of inorganic H2 permeable membranes namely (i) ceramic molecular sieving, (ii) dense ceramic ion transport, and (iii) dense metal.
Advantages and disadvantages of pre-combustion (decarbonization) – The advantages of pre-combustion (decarbonization) are (i) CO2 separation via solvent absorption or PSA is proven. The exhaust gas comes at elevated pressures and high CO2 concentrations significantly reduces capture costs, (ii) the compression costs are lower than post-combustion sources as the CO2 can be produced at moderate pressures, (iii) the technology offers low SOx and NOx emissions, (iv) the main product is syngas, which can be used for other commercial applications or products, and (v) a wide range of hydrocarbon fuels can be used as feedstock, such as gas, oil, coal, and petroleum coke, etc. The disadvantages are (i) the feed fuel is to convert fuel to syngas first, (ii) gas turbines, heaters, boilers are to be modified for H2 firing, (iii) higher costs and greater technology risk, and (iv) it requires major modifications to existing plants for retrofit.
Oxy-fuel combustion represents an emerging novel approach to near zero-emission and cleaner fossil fuel combustion. It is accomplished by burning the fuel in pure O2 instead of air. By eliminating N2 (nitrogen) in the combustion process, the exhaust of the flue gas stream is mainly composed of water and CO2, without any N2. High purity CO2 can be recovered by condensation of water. However, when fuel is burnt in pure O2, the flame temperature is much higher than that in a normal air-blown burner and the conventional material of construction for the burner is not able to withstand this high temperature. Hence, either the material of construction is to be improved or the flame temperature is to be lowered. The development of high temperature resistant materials has been slow because it is a major R&D (research and development) undertaking. There are a number of methods, which can be used to moderate the flame temperature, the most common being CO2 recycling. In CO2 recycling, a portion of the CO2 rich flue gas stream is recycled back to the burner to lower the flame temperature similar to that in a normal air-blown burner. Another method is to use water injection rather than CO2 recycling to control the flame temperature. This is often referred to as ‘hydroxyfuel’ combustion. Effectively, these two options allow the continual use of conventional refractory material until new high temperature resistant material can be developed.
A primary benefit of oxy-fuel combustion is the very high-purity CO2 stream which is produced during combustion. After trace contaminants are removed, this CO2 stream is more easily purified and removed than post-combustion capture. There are other benefits also such as reduction in NOx formation etc. When burning oil or coal, only two unit operations are needed for the combined removal of all other pollutants namely an electrostatic precipitator (ESP) or bag filter and a condensing heat exchanger (CHX)/reagent system. It is also possible to simplify the reagent system in the CHX to achieve total removal of SO2 with the CO2 stream for geologic storage. This further reduces the cost of unit operations for pollution abatement. The CHX increases the thermal efficiency of the boiler depending on the type of fossil fuel combusted, being the lowest for high rank bituminous coal and highest for natural gas.
Another benefit is the significant reduction in the size and capital cost of all plant equipment compared to conventional air-based combustion systems. This is due to the almost 5-fold decrease in the fire box volume and exit flue gas flow rates as N2 is eliminated in the combustion process.
The major disadvantage of oxy-fuel combustion is the high capital cost (primarily due to O2 requirements) and large electric power requirement inherent in conventional cryogenic air separation units required to generate O2. Oxy-fuel combustion is not currently used in typical large combustion systems because the air separation system is expensive and flue gas recycling is needed to be practiced in order to moderate flame temperature.