Module 3 CO2 capture: Pre-combustion (decarbonisation) and oxy-fuel technologies
Original text: S. Wong, APEC Capacity Building in the APEC Region, Phase II Revised and updated byand ICF International
In Module 2, the different methods of capturing CO2 from post-combustion flue gases were discussed. However, if the CO2 concentration in the waste gases increases or pressure increases or both, this could provide for easier CO2 capture. By rethinking the entire "combustion process", it is possible to design energy conversion processes with a high CO2 concentration waste gas stream. This can be achieved with pre-combustion (decarbonisation) andtechnologies.
By the end of this module you will:
- Understand the various approaches that have been developed to separate CO2 from pre-combustion processes, including their advantages, disadvantages and commercial readiness;
- Understand the application of oxy-fuel technologies including their advantages, disadvantages and commercial readiness; and
- Be able to determine appropriate applications of each of these technologies to different CO2 capture scenarios.
Post-combustion capture processes were outlined in Module 2. If the CO2 concentration in the waste gases increases or if the pressure increases, or both, CO2 capture could become easier if done before combustion, rather than after. Thus, by rethinking the entire "combustion process" for converting fossil fuels to energy, it is possible to design energy conversion processes, which also generate a high CO2 concentration waste gas stream. This can be achieved with pre-combustion (decarbonisation) and oxy-fuel combustion technologies.
In this module, the pre-combustion capture and oxy-fuel combustion technologies are discussed.
Pre-combustion CO2 capture (decarbonisation)
Pre-combustion processes 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(Kreutz et al. 2003, Williams 2002). These technologies are at or near the commercial demonstration stage for coal feed material and could offer a wide range of energy products, such as electric power, heat (via steam), hydrogen and chemicals.
A drawback ofis the low carbon dioxide concentration in the flue gases which leads to a relatively high energy penalty and high cost of carbon capture. Pre-combustion strives to reduce these penalties by decarbonizing the process stream rich in carbon dioxide before combustion of the remaining hydrogen rich fuel. To achieve decarbonisation of hydrocarbon fuels, they are first converted into a through the of a fuel with oxygen (or air). The syngas is a mixture of carbon monoxide (CO); hydrogen (H2); water (H2O); carbon dioxide (CO2), depending on the conversion process and the fuel, other components.
The syngas is an intermediate product, which can then be converted to produce:
- Integrated electric power, using the water-gas shift reaction; or
- – where a range of energy products including power, heat, hydrogen and synfuels and other chemicals.
- The process involved with each of these end energy products is described below.
Hydrogen (with excess fuel gas to generate steam/electric power)
The most widely used method today for producing hydrogen 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 nickel catalyst at a high temperature in a direct-fired furnace fuelled by methane. The catalyst is poisoned by sulphur, so any sulphur present in the feed must be removed. The synthesis gas 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, as described below.
In an effort to reduce the pollutants generated from the burning of coal, several economies including the US,and instigated clean coal programs. One of the elements of these clean coal programs is the gasification of coal. The gasification technologies could produce a gas stream, which is high in CO2 and at moderate pressure. The feed coal is gasified in oxygen (or air) to produce a syngas. The syngas is cooled to 200°C in syngas coolers generating high- 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°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 via Claus and tail gas clean-up plants. A pressure swing adsorption (PSA) unit can be used to separate 85% of the H2 from the sulphur-free syngas. The H2 exits at about 60 bars and high purity (>99.99%). The CO2 can be scrubbed from the syngas downstream of the sulphur 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 hydrogen production. Commercial plants have been built and successfully operated to produce hydrogen for refinery applications and chemical manufacture (for example, ammonia andproduction) based on a range of hydrocarbon feedstock. Experience with gasification technology has been growing rapidly.
Integrated electric power
The high-hydrogen content syngas can be burned in a turbo expander to produce electric power in a combined cycle setting (Figure 3.2). If the syngas is produced using gasification, the scheme is called (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.
Figure 3.2: Coal fired IGCC with pre-combustion capture of CO2. Source: Vattenfall.
IGCC is currently being used commercially in many plants worldwide by gasification of petroleum residuals to provide power, steam and hydrogen. The 140 MWPernis plant has been operating since 1998 at high availability on heavy residual fuel oils.
The three main types of coal gasifiers are moving bed, fluidized bed and entrained flow. These are described in Barnes (2009). 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 (the percentage of a year that the plant is up and available for production, meaning not in unscheduled shut down) and competition from pulverized coal generation plants and low price natural gas. Cost estimates vary for coal-fired IGCC plants, often above 3500 $US /kW (based on a Harvard study).
The ChevronTexaco gasifiers (slurry feed) and the Shell gasifiers (dry feed) are popular. These are both oxygen-blown, entrained-flow gasifiers. Figure 3.3 shows the internal of a Shell gasifier and a Texaco gasifier.
Figure 3.3: Pictorials showing the internal structure of (left) a Shell Gasifier and (right) a ChevronTexaco Gasifier (courtesy of Shell and ChevronTexaco).
For the slurry feed ChevronTexaco gasifier, without CO2 capture, the coal is ground and slurried with water and then pumped to the gasifier vessels where it reacts with oxygen. The products from gasification are quenched with water and the saturated gas is cooled. Condensed water and minor impurities are removed. The gas is then passed through a COS hydrolysis reactor and fed to an acid gas removal plant for removal of sulphur compounds. The clean fuel gas is passed through a turbo-expander and fed to the gas turbine combined cycle plant. For CO2 capture, the quenched gas from the gasifier is fed to a CO-shift converter prior to cooling. The acid gas removal unit removes CO2 as well as sulphur compounds. Oxygen is supplied to the gasifier via a cryogenicunit.
For the dry feed Shell gasifier, the coal is dried and ground and fed to the gasifier vessels via lock hoppers. The gasifier product gas is cooled in a waste heat boiler, which generates high-pressure saturated steam. The gas is further cooled and scrubbed with water, passed through a COS hydrolysis reactor and an acid gas removal plant. The clean fuel gas is fed to the gas turbine combined cycle plant. For CO2 capture, the wet syngas is fed to a shift converter and the CO2 separated. Oxygen to the gasifier is produced by cryogenic air separation.
Through IGCC, sulphur is typically removed from the syngas and produced as sulphur or sulphuric acid for sale. NOx emissions are controlled by firing temperature modulations in the gas turbine. Particulates are removed from the syngas by filters and a water wash prior to combustion so emissions are negligible.
The cost of CO2 capture in IGCC depends strongly on the type of gasifier. The ChevronTexaco gasifiers are expected to show lower incremental energy penalties and lower cost for CO2 capture than the Shell gasifiers. Slurry feed/quench gasifiers also tend to have lower capital costs but they have lower thermal efficiencies, either with or without CO2 capture (Thambimuthu et al., 2002).
As mentioned above, to enable CO2 to be captured, the fuel gas has to be fed to a catalytic shift reactor where most of the CO is reacted to steam to give H2 and CO2. 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 has to be taken from the steam cycle and added to the fuel gas feed to the shift converter (it needs steam for the water gas shift reaction). Therefore, slurry feed gasifier has lower incremental energy penalty for CO2 capture than dry feed gasifier.
Slurry feed gasifier based IGCC has a lower capital cost than dry feed based IGCC as lock hopper feed systems and fuel gas recovery boilers are relatively expensive. The lower cost of the slurry feed gasifier more than compensates for the high thermal efficiency of the dry feed gasifier.
For coal-based IGCC, SO2 emissions are very low and NOx and particulates emissions are below recent pulverized coal plants permit limits, so there are environmental benefits from IGCC. It should be noted that IGCC is more expensive for the generation of electricity than conventional pulverized coal combustion, with no CO2 capture in both cases.
Syngas is a good building block, as it can be used to produce a wide range of energy products. The greatest flexibility offered is polygeneration, in which 'syngas' can produce steam, electric power, hydrogen and chemicals (such as methanol, Figure 3.4. Similar to the other schemes in pre-combustion CO2 capture, CO2 capture will occur after the water gas shift reactor.liquids) in a single plant complex. This is particularly appealing to developing economies, because of the range of energy products produced. An example of a coal polygeneration scheme is shown in
Figure 3.4: An example of a schematic for coal polygeneration (Williams, 2003).
Pre-combustion capture technologies
A number of different separation technologies including solvent, adsorbent and membrane technologies can be applied to separate CO2 from the products of gasification.
The conventional technology is physical absorption (e.g. using Selexol) in a two-stage process which removes hydrogen sulphide and then captures CO2. Solvent units are available at scale. 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.
Adsorbents can be used to separate CO2 from post-combustion flue gas streams downstream of the water gas shift reaction. Adsorbents under investigation include Hydrotalcites (HTC) and 13X (a zeolite). Both temperature swing adsorption (TSA) and vacuum/pressure swing adsorption (VSA/PSA) can be used to recover the CO2 from the adsorbent.
Xiao et al (2009) report on the design of a process to capture CO2 from an air-blown lignite gasifier. Some advantages of the process include:
- No need for a supply of N2 for use in the gas turbine.
- The water content of the lignite reduces the need for steam injection into the water gas shift reactor.
The CO2 is at low pressure when recovered via VSA/PSA and needs to be compressed for storage.
Current studies suggest that the advantages over TSA are simplicity, less adsorbent required and reduced cycle time. Trials on real synthesis gas are currently underway in Australia.
Advanced membrane-based gas separation systems are currently being developed to combine the gas shift reaction and hydrogen 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 (see Figure 3.5). The maximum temperature of ~ 475°C insures fast chemical kinetics and good water gas shift equilibrium performance is obtained by continuous removal of the H2 product.
Figure 3.5: Schematic of a Hydrogen Separation Membrane Reactor (HSMR).
There are three major classes of inorganic H2 permeable membranes:
- ceramic molecular sieving;
- dense ceramic ion transport; and
- dense metal.
One example of the dense metal membranes is 1-3 um Palladium/silver (Pd/Ag) alloy foil (dense) sputtered on single crystal silicon developed by(Lowe and Andersen, 2004). Palladium (Pd) membranes have been studied for potential application of H2 separation from fuel gas mixtures (Buxbaum and Kinney, 1996), as it will leave behind a gas residue enriched in CO2. Pd is an active oxidation catalyst and therefore is not suitable for H2 streams that contain O2. Because of the high material cost of Pd, many researchers have turned to thin films of Pd.
Alloying Pd with Ag increases thefor H2 and reduces H2 emblement (H2 can attack the material making it brittle and causing failure). Thin film Pd alloy membranes look very promising. This development could significantly reduce capital cost and improve the efficiency of CO2 capture.
Other developments in polymide membrane systems applicable to IGCC were outlined in Module 2.
Advantages and disadvantages of pre-combustion (decarbonisation)
The advantages of pre-combustion (decarbonisation) are:
- CO2 separation via solvent absorption or PSA is proven. The exhaust gas comes at elevated pressures and high CO2 concentrations will significantly reduce capture costs;
- The compression costs are lower than post-combustion sources as the CO2 can be produced at moderate pressures;
- The technology offers low SOx and NOx emissions;
- The main product is syngas, which can be used for other commercial applications or products; and
- A wide range of hydrocarbon fuels can be used as feedstock, such as gas, oil, coal petroleum coke, etc.
The disadvantages are:
- The feed fuel must convert fuel to syngas first;
- Gas turbines, heaters, boilers must be modified for hydrogen firing;
- Higher costs and greater technology risk; and
- 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 oxygen (O2) instead of air (O2 and N2). By eliminating nitrogen in the combustion process, the exhaust of the flue gas stream would be composed mainly of water and CO2, rather than N2. High purity CO2 can be recovered by condensation of water. However, when fuel is burnt in pure oxygen, the flame temperature is much higher than that in a normal air-blown combustor and the conventional material of construction for the combustor would not be able to withstand this high temperature. Therefore, either the material of construction has to be improved or the flame temperature has to be lowered. The development of high temperature resistant materials has been slow because it is a major R&D undertaking. There are a number of methods, which could 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 combustor to lower the flame temperature similar to that in a normal air-blown combustor. A simplified schematic of the oxy-combustion/CO2 recycle process is shown in Figure 3.6. 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 would allow the continual use of conventional refractory material until new high temperature resistant material can be developed.
Figure 3.6: A schematic of oxy-fuel combustion with CO2 recycle. Source: Vattenfall.
A primary benefit of oxy-fuel combustion is the very high-purity CO2 stream that is produced during combustion. After trace contaminants are removed, this CO2 stream is more easily purified and removed than post-combustion capture. Other benefits also are apparent. For instance, when the scheme is implemented with 70% recycle of the predominantly CO2 flue gas back to the combustor, NOx formation is reduced by up to 80%. This is possible because of the reduction in thermal NOx due to the absence of N2 in the flame and also part of the recycled NO is reduced to molecular nitrogen in the flame. When burning oil or coal, only two unit operations are needed for the combined removal of all other pollutants: 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 rankand 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 nitrogen is eliminated in the combustion process.
Oxy-fuel combustion could be an attractive option for retrofit of existing steam cycle power stations (McDonald et al., 1999). The modifications that would need to be made at the power station would be relatively minor. One issue that must be dealt with is the potential for air leakage into the furnace, as the retrofit unit cannot be sealed to 100% airtight. This would impact on the CO2 concentration in the flue gas stream and hence reduce CO2 purity. It is found that as little as 3% air leakage is possible, which would result in a flue gas with about 95% CO2 purity. Many applications do not require 100% pure CO2. If a 95-98% purity CO2 product is acceptable (for geologic storage, this CO2 purity would not be a problem), 95% purity oxygen could be used and this would substantially reduce the cost of oxygen.
Singh et al. (2003a, 2003b) presented a techno-economic comparison of the performance of a CO2 capture using MEAand O2/ CO2 recycle combustion from an existing coal-fired power plant. Their scenario involved the power plant maintaining its original output to the power grid. As a considerable amount of supplementary energy must be supplied to the CO2 separation processes, in this scenario supplementary energy was generated using gas turbine combined cycles, gas turbines and steam boilers. These "auxiliary" units are fuelled with natural gas. The CO2 generated by the combustion of natural gas was not captured in this study. The results showed that both processes were expensive options to capture CO2 from coal power plants.
Oxy-fuel combustion for power generation is an emerging technology. To date, no commercial unit has been built, although there are several demonstration projects underway. Large-scale oxy-combustion has been used in glass and steel melting furnaces for high temperature application in these industries. Oxy-fuel for coal-fired plants with carbon capture is being demonstrated in a 30 MW pilot plant at Schwarze Pumpe in Germany. Other demonstrations are at Callide (Australia) and(Spain) and Lacq (France). Development of tail-end CO2 purification and hybrid turbines is still required for commercial demonstration.
The major disadvantage of oxy-fuel combustion is the high capital cost (primarily due to oxygen requirements) and large electric power requirement inherent in conventional cryogenic air separation units required to generate oxygen. Oxy-fuel combustion is not currently used in typical large combustion systems because a) the air separation system is expensive and flue gas recycling must be practiced in order to moderate flame temperature.
Cryogenic air separation is, however, a mature technology. Different consortia are developing ionic transport membranes for air separation with U.S. Department of Energy and(EU) funding for commercialization by 2010. The ionic transport membranes with oxygen permeable ceramics use multi-component metallic oxides with vacancies built into the oxide by ion substitution. Oxygen permeates at a high flux and 100% selectivity. This technology can substantially reduce the cost of oxygen and the energy requirement compared to cryogenic air separation.
The challenge faced in the development of oxy-fuel systems is the design configurations and material of construction of combustors, boilers and turbo-machineries to take advantage of the higher temperature with burning the fuel in oxygen. Operating at higher temperature generally means higher thermodynamic cycle efficiency. The full potential can only be realized with the development of new combustor/boiler designs that are made with high temperature-tolerant materials. In turbine applications, one proponent of "hydroxyfuel" combustion isSystems Inc. (CES), of California. The CES technology is currently at the demonstration stage. In the form that it is being developed, oxygen is added to gaseous fuel and the oxy-fuel mixture ignited to produce combustion gases which drive a turbine for power generation. This technology is developed from the rocket propulsion industry. With current materials, the product gas stream must be cooled and this is accomplished by injection of water or steam. The result is a proprietary "steam generator". The working fluid for the turbine would be a combined steam/CO2 gas mixture.
- Pre-combustion (decarbonisation) and oxy-fuel combustion technologies offer very attractive waste gas streams for CO2 capture.
- For pre-combustion technologies, the exhaust gas comes at elevated pressures and high CO2 concentrations, which will significantly reduce capture costs. Compression costs can be reduced when CO2 can be produced at moderate pressures. This technology also offers low SOx and NOx emissions. CO2 separation via solvent absorption or PSA is proven.
- Oxy-fuel combustion technology generates an exhaust gas stream almost exclusively composed of CO2 and H2O. CO2 capture from this waste stream is cheap and easy, using condensing heat exchangers. It also enables an order of magnitude (90%) reduction of NOx emissions to be achieved.
- The availability of such waste streams for CO2 capture depends on the timing of the commercialization of the technologies.
- Gasification technology is commercial. Hydrogen and chemical production from gasification and from natural gas reforming are commercial. These plants have produced some very attractive waste gas stream for CO2 capture. IGCC plant gasifier exhaust would also be attractive, if these plants were available. The exhaust would be further processed in a water gas shift reactor to produce an exhaust stream suitable for CO2 capture with solvent absorption or PSA.
- Oxy-fuel combustion technology is not yet commercial, but several demonstrations for power systems are underway.
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