Alternative Fuels: How Aviation is Next in Line

British Airways Are Experimenting With Biofuels

Unlike vehicle emissions from cars, air travel accounts for a relatively small proportion of global C02 emissions. It does pale against many other forms of pollution, but it has become a standard bearer for a greener world in recent years. The environmental impact of all human activities is being measured in a campaign to cut emissions across the world. This has run from transportation, to heating, energy generation to food production. It has even looked at the environmental cost of drug production. With all this in mind, it's sensible to see if air transport can be made more fuel efficient and indeed, greener.

However, this proportion is steadily growing as aeroplane travel becomes an increasingly popular and accessible alternative to road and rail throughout the world, and as the automotive industry puts many measures in place to reduce its own carbon footprint. The industry doesn’t have the flexibility of the automotive industry to trial and test new technologies and fuel alternatives as freely; developing technology and insurance in aviation is a lot more costly and lengthy than that of automotive technology and motor trade insurance. Both British Airways and Etihad Airways have been experimenting with alternative biofuels, but replacing standard aviation fuels is a logistical and technical challenge as finding a truly efficient alternative would mean sourcing one that doesn’t require excessive transport, or land occupied by trees and crops. The big drive in reducing emissions from surface transport means that now the shift is turning to the aviation industry.

The industry is taking this seriously. Etihad Airways has teamed up with the Masdar Institute of Science and Technology and Boeing on a largescale research project that will aim to cultivate and bring to the mass market a sustainable biomass suitable to use as aviation fuel. The companies have together created the Sustainable Bioenergy Research Project, based in Abu Dhabi. It will find a solution by studying how the Earth’s existing resources, such as algae and arid landscapes can contribute to producing biofuel. They have already found one viable method; through a combination of salt water farming, mangrove forests and cultivating salicornia, they have found this can be a potential way of making biofuel.

In addition, British Airways has joined forces with American energy company, Solena, to build in East London Europe’s first sustainable jet fuel plant. The revolutionary plant will be built to convert various waste materials that would otherwise be destined for landfill into a gas substance. It will then convert the gas into liquid aviation fuel through a cutting edge new process called Fischer Tropsch synthesis. The facility, due for completion in 2014, will produce 16 million gallons of green jet fuel per year from 500,000 tonnes of waste. This is more than twice the amount required to convert all of British Airways’ flights from London City Airport carbon neutral.

Perfect flight

Meanwhile, air traffic control units are doing their bit to aid reduction of C02 emissions. The British NATS (National Air Traffic Control Service) has created the ‘perfect flight’ profile. This involves planes taking off and landing smoothly, and taking the most direct routes to their destinations. Descent would be made at a higher rate to save fuel. The NATS conducted a test flight recently between London and Edinburgh, which cut C02 emissions by a whole tonne.

Air France and Airbus also teamed up last year to combine several methods of fuel saving. Their Continuous Descent Approach, which cut down on biofuels and optimised air traffic management, cut emissions by half.

Next generation air planes

Boeing recently launched an exciting new model – the 787 Dreamliner – which cost around $32 billion to produce. It is made of light weight composition materials and uses around 20% less fuel than its older counterpart, the Boeing 767. Certain design features aid its green capabilities; for example its streamlined raked wings reduce wind drag. The inside cabins are also designed to be a lot more comfortable for the passenger, with the build material enabling better air quality and pressure, and more space.

Airbus is also showing its capabilities in the industry with the launch of its own next generation aeroplane, set for completion in 2013.

Engine technology

Aerospace companies are looking at the possibility of using open rotor engines, which could enable substantial emission reductions. These could be used on medium and short haul flights, which could make a huge difference to overall fuel emissions of the industry. Open rotor engines have been around for a long time, having been introduced in the seventies. The technology uses an advanced, multi-blade version of the traditional propeller, which improves efficiency. Introduction of these engines could reduce carbon emissions by up to 30%.

NASA is also playing its part, having long since run many research projects in aviation. It has created the N + 3 programme, which focuses on using technologies that are three generations more advanced than those in use today. In 2010, Massachusetts Institute of Technology worked with the NASA N + 3 programme to produce an aircraft with the combination of two airframes that were merged to create a wide fuselage. This provided extra lift for rapid ascent and landing. 

It is clear that big steps are being taken by the aviation industry to follow in the footsteps of the automotive industry in reducing carbon emissions; it has taken some time to get there, but the technology that is being developed could revolutionise the way we travel and the impact it has on our planet.

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Debottleneck crude-unit preheat exchanger network inefficiencies

In this case history, a crude distillation unit (CDU) preheat train network in a Saudi Aramco refinery was simulated and analyzed for anticipated modifications to the network. This analysis helped eliminate inefficiencies in the network, and, based on the insights from the analysis, various options were generated and the existing network was reconfigured. The reconfiguration allowed the temperature of the crude preheat network, which processes Arab Light crude oil, to be increased to the maximum of 277°C from a previous temperature of 261°C.

Existing configuration.

Desalted crude from the tank is heated by the crude column top pumparound, light gasoil (LGO) product, heavy gasoil (HGO) product, LGO pumparound (LGO PA), HGO pumparound (HGO PA), heavy vacuum gasoil (HVGO) pumparound and vacuum residue (VR) product, as shown in Fig. 1 in exchangers E1 to E7, respectively. The current crude preheat temperature entering the CDU furnace is around 261°C. This exchanger network is validated using heat exchanger design software and by adjusting the fouling coefficients.

Modifications required.

The base-case network was altered for anticipated modifications in the future. The reasons for the modifications are listed below:

Vacuum slop circuit. In the current configuration (Fig. 2), the vacuum slop is recycled to the vacuum tower through the vacuum furnace. The purpose of this recycle is to recover the VGO components and send the VGO to the hydrocracker; however, this is not achieved in the current operation due to vacuum furnace limitations and insufficient separation in the wash section. As a result, this vacuum slop stream (which is lower in viscosity) goes with the vacuum tower bottoms. The mingling of streams deteriorates the feed to the asphalt oxidizer and creates operational problems in meeting the penetration property of the asphalt.

To address this concern, the vacuum slop stream from the vacuum tower is available at a temperature of 380°C, which is withdrawn as a separate cut and is used to increase the preheat temperature of the crude. This proposed new exchanger is configured to be in parallel with the existing heat exchanger E4 in Fig. 1. Fig. 3 shows the rerouting of the vacuum slop.

Future splitter configuration. To meet the clean gasoline specification of 1% benzene in gasoline, the existing naphtha splitter must remove the benzene precursors in the catalytic reformer feed by increasing the initial boiling point of the heavy naphtha. This process requires a higher reboiler duty. In addition, the heavy naphtha from the hydrocracker needs to be processed in the naphtha splitter, as this feed also contains benzene precursors.

Currently, hydrocracker heavy naphtha is not part of the naphtha splitter feed. The hydrocracker heavy naphtha feed volume is 12,500 barrels per day (bpd), and the existing naphtha splitter capacity is 23,000 bpd. Figs. 4 and 5 show the naphtha system’s current and planned configurations, respectively. As the current naphtha splitter cannot handle this higher throughput with higher reboiler requirement, the existing naphtha splitter will be mothballed. The existing reboiler, which uses HGO PA flow and gives a duty of 10.4 million kilocalories per hour (MMkcal/hr), will also be mothballed.

High-pressure steam will be used in the reboiler of the new naphtha splitter to meet the higher reboiler requirements. For the column to be in heat balance, this 10.4 MMkcal/hr of heat removal is required. In the proposed exchanger network, this stream (HGO CR) will be used to preheat the crude. 

 Synthesis of crude preheat train.

A new, preliminary heat exchanger network (Fig. 6) was synthesized to accommodate the above modifications. While modifying the crude preheat train network, the following impact on the equipment was kept in mind:

·         Prevention of vaporizations in the furnace pass-control valves, as it is difficult to control two-phase flows across pass-control valves. Inadequate flow in the furnace pass flows will also lead to coking

·         Column heat balance.

·         Column hydraulics.

·         Impact of hot streams going directly to the other unit.

The changes made in the base-case network are listed below:

·         Exchanger N1 was added parallel to E4 (see Fig. 6) using vacuum slop (vacslop) and vacuum residue ex-E7 as the hot fluid. This modification is required to improve the viscosity of the vacuum residue to the asphalt oxidizer. The current viscosity of the feed to the asphalt oxidizer is 1,500 centistokes (cst), and the required viscosity is 2,000 cst.

·         Another exchanger N2 (E5-2, similar to E2) was added parallel to E2 using HGO PA fluid ex-E5 (hereafter referred to as E5-1) as the hot fluid. This modification is performed to accommodate the 10.4-MMkcal/hr duty in the HGO PA circuit.

·         Increased area in E4 from the 2-parallel-1-series arrangement to a 2-parallel-2-series design and added cooler N3 downstream of E4.

Due to the first two modifications, the inlet temperature to E4 has increased, which decreases the logarithmic mean temperature difference (LMTD) available across the unit. Since E4 is the LGO PA exchanger, the column will not be in heat balance if the required heat removal is not performed. The required duty was 18.8 MMkcal/hr, and the available duty was 12.7 MMkcal/hr (see Table 1). Therefore, additional area and a cooler were added in the LGO PA circuit to meet the duty requirement of the column.

The required HGO PA duty is 26.8 MMkcal/hr, and the available duty is 29.8 MMkcal/hr. As the heat removed in HGO PA is higher by 3 MMkcal/hr, the requirement of LGO PA duty will come down by 3 MMkcal/hr. As both LGO and HGO are mixed outside of the column and go to the diesel hydrotreater (DHT), the splitting of the duty between LGO and HGO pumparound is not a concern from a separation point of view. However, it does impact the column draw temperature, which will slightly reduce the LMTD across E3 (HGO product/crude exchanger) and E5 (HGO PA/crude exchanger).

Results of network modification.

In the modified network, the obtained preheat temperature was 266°C. The duty, LMTD and area of each exchanger in the network are presented in Table 1. From Table 1, it can be observed that:

·         Exchanger E6, which has a higher area, is experiencing the lowest LMTD; therefore, any modification that increases the LMTD will significantly increase the heat recovered from E6.

·         The exchanger preceding exchanger E6 is heated by HGO circulating reflux (CR), which is at 337°C; this is higher than the hot stream (HVGO CR) temperature of E6, which has decreased the LMTD in E6.

This preliminary network was analyzed for possible improvement in the preheat temperature. The analysis indicated that heat recovery can be increased by 45% by boosting the area by 56% (see Table 2).

The analysis also indicated that the driving force across exchanger E7 further limited the heat recovery. Fig. 7 displays the driving-force plot. The figure indicates that the driving force in E7 can be increased by decreasing the inlet temperature in E7. This temperature adjustment can be achieved by operating E5 in parallel with E7.

Case 1. Based on the insights derived from Table 1 and Fig. 7, to improve the heat recovery, the crude stream in E7 and E5 was split by operating E5 in parallel with E7. The objective of this modification is to increase the LMTD across E7 and E6. However, it also decreases the LMTD across E5-1. The net effect is shown in Table 3, and the modified network is shown in Fig. 8. With this arrangement, the preheat temperature has increased from 266°C to 269°C.

Case 2. From LMTD and approach data in Table 3, it can be inferred that heat recovery in E5-1 can still be improved by increasing the area. Hence, another case study was performed by adding two similar exchangers in a series in E5-1. The results are tabulated in Table 4. The preheat was found to be increased to 277°C.

The HGO PA is now providing an extra 4.2 MMkcal/hr more than required, which will reduce the LGO PA duty requirement by the same amount for the column to be in heat balance. Then, the required LGO PA cooler duty comes down to 2.6 MMkcal/hr.

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Optimize hydrogen management for distillate production

Moving more distillate streams to diesel production and/or fuel oil (FO) production is a major refining activity. The distillate qualities and quantities, hydrogen price and consumption, product demand and prices, and refinery configuration constraints are key factors for these decisions.

Producing higher-quality products from poorer-quality crudes requires more hydroprocessing. These distillate streams, e.g., heavy kerosine (HK), gasoils (GOs) and light cycle oils (LCOs), etc., are also used as cutter stocks to upgrade vacuum residues (VRs) and downgraded as low-value FO products. FO and VRs are major constrains if no resid-upgrading facilities are available.

The heavy distillate streams from the fluid catalytic cracking unit (FCCU) must be hydrotreated to upgrade todiesel specifications. Hydrotreating consumes substantial hydrogen quantities, and this process adds more costs. When adding new hydrogen-consumer streams, hydrogen demand can exceed available refinery supplies. In such scenarios, optimizing existing hydrogen supplies is the key to improving the total profitability of the refinery.

A simple reliable optimization tool for routing intermediate distillate streams maximizes benefits while meeting all constraints of hydrotreating capacity, hydrogen, VR utilization, product specifications and prices. The Excel-based calculator is generic for hydrogen management, and it also fits into various refinery configurations where different resid-evacuation options are practiced.

Hydrogen management.

Processing opportunity crude oils and meeting critical product specifications of EURO III, IV and V are the real challenges for refiners. The quality of straight-run (SR) distillate streams obtained from the processing of high sulfur (S) and low API crude oils is considered inferior. Thus, refining higher-quality products from poorer-quality crudes has increased hydrogen addition. Conversely, LCOs (from the FCCU) are such intermediate distillate streams; they are also routed through the diesel hydrodesulfurization (DHDS) unit to meet product specifications. These streams (especially LCO) consume substantial hydrogen quantities, thus increasing processing costs to meet final diesel specifications. Under these conditions, optimizing hydrogen consumption is the key to total profitability.

Planning tool. To fully optimize the routing of intermediate distillate streams and hydrogen management, additional requirements for these streams must be added to existing planning and optimization tools. These tools must not only determine hydrogen and hydrocarbon routings, but also accommodate individual unit capacities and refinery configuration constraints.

These intermediate distillate streams, in general, are also routed to residue evacuation when no modern resid-upgrading facilities such as coker/visbreaker/solvent deasphalting (SDA) are available. Adding intermediate distillate streams as cutter stock with residues produces FO, when capital investment may not be required. In the presented study, an optimization tool evaluates the routing of intermediate distillate streams to the diesel pool and/or resid-upgrading while meeting the refinery configuration constraints.

More hydrogen demand. Hydrogen consumption for intermediate distillate streams has grown significantly. Hydrogen-addition processes, in general, are preferred due to two factors. First, new environmental regulations over transportation fuels require higher-quality refinery products. Second, the differential prices for light- and heavy-crude oils continue to increase as light-crude reserves are declining, and supplies of heavy-crude oils are increasing. Refiners are taking advantage of these spreads; they are incorporating more lower-cost, heavier, sour, opportunity crudes into the feedslate.

Under these conditions, it is essential to understand the crude oils and their hydrogen content. Increased hydrogen consumption is an additional cost to process these crude oils. Therefore, to produce the same yields of transportation fuels either carbon rejection and/or hydrogen-addition processes must be selected. In actuality, even with incremental new carbon-rejection process capacity, additional hydrogen consumptions and, thus, their enhanced process capacities are preferred. This processing scheme enables optimizing hydrogen management for the refinery. The presented optimization tool can help facilitate efficient hydrogen usage in various resid-upgrading scenarios.

Problem definition.

While processing high-sulfur crude oils at a crude distillation unit, the processed distillate qualities were considered inferior. These intermediate distillates and LCO (from the FCCU) streams are routed through the DHDS unit to meet diesel-product specifications. These streams (especially, LCO) consume additional hydrogen to meet final diesel specifications. However, there are capacity limitations for hydrogen (maximum of 35 tpd) and hydraulic limits for DHDS capacity (maximum of 6,000 tpd). This is a common problem for any refinery. The presented study can be replicated to any other refineries with many commonalities and/or additional constraints.

In the presented case, the VR is being evacuated as FO, where it consumes distillates as cutter stock to meet the final product specifications. Two grades of FO (180 cst and 380 cst) are produced when the cutter profiles are different. Thus, the available distillate streams are being used either for diesel production, which has a higher value and/or routed to FO production, which is needed for upgrading VR.

The minimum VR production is approximately 3,500 tpd while processing 18,000 tpd of crude oils (6 MM tpy crude oil processing basis). The distillate streams available at this refinery are HK (high sulfur), GO (high sulfur) and LCO (high sulfur), etc. Fig. 1 shows the processing flow diagram for routing distillate streams. The cutter requirement depends on the quality of the produced distillate products. However, while optimizing the overall FO production, one must consider the total hydrogen consumption for upgrading both SR and cracked feedstocks.

A simple optimization tool was developed for optimal routing of the distillate streams to diesel and/or FO production. The study considered all constraints of meeting DHDS capacity, hydrogen capacity, VR utilization and product specifications, prices, etc.

METHODOLOGY

Diesel production is always the first choice due to its higher value over FO production. When distillate streams are routed through the DHDS unit, hydrogen is consumed to meet diesel-product specifications and, of course, increases processing costs. However, FO production needs no additional cost, but FO demand is declining. In this scenario, VR upgrading is one of the limits when equivalent distillates are downgraded. Thus, an optimal decision must be made between additional hydrogen consumption vs. producing more low-value FO products.

Hydrogen consumption.

In diesel hydrotreating, hydrogen consumption is governed by feed properties and product specifications. The affecting variables are carbon/hydrogen (C/H) ratio, S, basic nitrogen (N) and metal content, etc. To estimate the C/H ratio, a correlation as a function of specific gravity is applied. In this study, C, H and impurities (I) are evaluated in a balanced approach, especially across the DHDS unit to determine H₂ consumption while upgrading distillates. The estimated H consumption is based on these assumptions:

·         Data for distillates are from refinery test runs

·         H2 consumptions are based on the distillate quality

·         All components, other than C and H, are considered as impurities for the calculations

·         Estimated cost for H2 is $2,150/ton.

In this approach, the Excel-based optimization tool was developed to maximize benefits by optimum routing of intermediate streams to diesel (via DHDS) and/or FO production. The spreadsheet is enabled with macro, where input and output are linked with a single click button, as shown in Fig. 2. The model has provision to enter all inputs for the total distillate quantities available to routing and qualities, product specifications and prices, cutter profiles to meet product specifications and all process limits, e.g., DHDS capacity, hydrogen and VR upgrading, etc. These input data are treated as the Base Case, which is normally being practiced. The output data are reported as H₂-consumption profiles for each stream, capacity utilization, optimum routing of intermediate distillates, final product profiles and overall benefits.

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Visbreaking Process

Visbreaking is a non-catalytic thermal process that converts atmospheric or vacuum residues via  thermal cracking to gas, naphtha, distillates, and visbroken residue. Atmospheric and vacuum residues are typically charged to a visbreaker to reduce fuel oil viscosity and increase distillate yield in the refinery.

Advantages of the Foster Wheeler/UOP visbreaking process are:

• High sulfur fuel oil reduction
• Reduces distillate cutter stock requirements, making the distillate available for more valuable transportation distillate fuels
• Low cost upgrading ($900 / BPSD US Gulf Coast basis)

There are two types of visbreaking technology that are commercially available: the ‘coil’ or ‘furnace’ type and the ‘soaker’ process. In the coil process, conversion is achieved by high temperature cracking for a predetermined, relatively short period of time in the heater. In the soaker process, which is a low temperature/high residence time process, the majority of conversion occurs in a reaction vessel or soaker drum, where the two-phase heater effluent is held at a lower temperature for a longer period of time.

Foster Wheeler has utilized both soaking coil and soaking drum technologies in the design of visbreakers and thermal crackers. A number of the units designed by Foster Wheeler have integrated visbreaking and thermal cracking sections.

In a ‘coil’ type operation, charge is fed to the visbreaker heater where it is heated to a high temperature, causing partial vaporization and mild cracking. The heater outlet stream is quenched with gas oil or fractionator bottoms to stop the cracking reaction. The vapor-liquid mixture enters the fractionator to be separated into gas, naphtha, gas oil and visbroken resid (tar). The visbroken bottoms are then blended with lighter materials (cutter stock) to meet fuel oil specifications. The fractionated visbreaker gas oil is often used as the cutter stock.

Visbreakers can be configured with vacuum flashers on the tar stream to produce more heavy gas oil distillate and can also be configured as two-stage visbreaker/thermal cracker for maximum yield of lighter distillates.

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Flue Gas Treatment

Treating flue gas minimizes or eliminates both the environmentally unacceptable nitrogen oxide (NOx) and sulfur dioxide (SO2) emissions as well as the collecting of unburned solid particles before they escape into the atmosphere. Both techniques involve a number of steps

NOx Reduction Techniques

Fuel Selection

Control of NOx pollutants begins with the proper fuel selection. A coal with a sufficiently low fuel nitrogen (less than 1.5%) as shown in a routine fuel analysis may eliminate the need for any NOx reduction techniques. Natural gas has no nitrogen in the fuel; fuel oil typically has a lower nitrogen content than coal. Coal reactivity may also be decreased to slow down combustion and decrease temperatures to minimize NOx production. Lower flame temperatures will result in a lower level of NOx production in oil and gas-fired systems. Boiler systems that have highly turbulent flames and high temperature furnaces usually need lower fuel nitrogen than is normally available in the required quantities. Reduction techniques would then be needed.

Furnace Sizing

This step is only practical if a new facility is planned. By increasing the furnace cooling surface, the high temperature and time aspects of NOx production can be reduced. Another benefit is the increased flexibility in coal purchasing especially in specifications and price.

Burner Selection

Selecting a burner relative to furnace size limits the oxygen availability to form NOx while simultaneously shaping the flame to minimize the 2800 degree residency time. This permits the use of moderate and low-nitrogen coal and meeting NOx emission regulations. This method generally produces good results.

Low Excess Air Combustion

This technique also limits the availability of oxygen and increases the efficiency of a high-turbulence burner. There is little change in the 2800-degree residency time and only fair results can be expected. Also, when this technique is used, a fairly complex series of controls must be installed to maintain the best combustion. Coal ash problems may also arise due to the reduced oxygen levels.

Two-Stage Firing

This technique also limits oxygen availability by adding excess oxygen, needed for complete combustion, through overfire air ports. The rate of combustion is lessened and the 2800 degree residency time is decreased. It produces good results with moderate-to-high fuel nitrogen coals. There is the possibility of decreased carbon burnout and furnace heat absorption and an increase in fireside deposits and potential corrosion.

Off-Stoichiometric Firing

This method also limits oxygen availability and flame temperature but for different levels of burners on large units. It is fairly successful and easily applied to existing units. As in the two-stage firing technique, there can be carbon loss and increased slagging.

Flue Gas Recirculation

This method takes advantage of the reaction that tends to drive fuel nitrogen towards N2 in the presence of NO. With NO present, there is a tendency to minimize the formation of thermal NOx by driving the reaction toward the more stable N2. This is a “last resort” technique when regulations must be met with high-nitrogen coal. It is the most effective method but it is the most expensive and difficult to install. Combustion control equipment and operating requirements with fans, ductwork and air balancing increase the complexity and can create problems.

Selective Non-Catalytic Reduction (SNCR) and Selective Catalytic Reduction (SCR)

There are two types of SNCR control technologies for retrofit to industrial boilers; one uses ammonia as the reducing agent; the other urea.

They reduce NOx in the flue gas to molecular hydrogen at high temperatures between 1600 and 2000 degrees Fahrenheit without a catalyst. With a catalyst the conversion takes place at a much lower temperature range, roughly 575-800 degrees Fahrenheit. This is called SCR. Typically these agents are injected in the post-combustion region.

Because of the significant load variations in industrial boilers which cause the optimum temperature zone to shift location in the boiler, the application and effectiveness of this type of flue gas treatment is limited.

Solid Particle Removal

The removal of solid particles from the flue gas (also called particulate emissions) is an important part of the combustion process, as proper system selection and the maintenance of that system can significantly affect plant operating costs, as well as legislative compliance. These solid particles are basically the nonburnable elements in coal that leave the furnace and boiler after combustion.

There are a number of control techniques that can be applied, varying with the type of coal and combustion equipment installed (stoker, fluidized-bed or pulverized-coal firing):

Mechanical Collection

This is the oldest form of particulate collection. It extracts ash particles from the flue gas circular air current, which forces the particles to the outer portion of the current and downward into a storage hopper. It is typically found in stoker-fired boilers. Some spreader stoker fired boilers use mechanical collectors ahead of precipitators or baghouses for reinjection of the flycarbon and for an increase in overall collection efficiency.

Sidestream Separation

This is an additional technique applied to mechanical collection to improve collection efficiency. In operation, some 10-20% of the flue gas is removed from the bottom hopper of the collector and cleaned in a small baghouse. This can in-crease ash collection efficiency by up to 35-50%.

Electrostatic Precipitators

These devises operate on the principle that the ash particles can accept an electrical charge. Particles pass through an electrical field and are attracted to a vertical metal plate, where, periodically, they are shaken loose and collected in the collection hopper.

Baghouse Collectors

These systems, quite simply, work on the same principle as a household or industrial bag-type vacuum cleaner. The ash is removed in one of two ways; a reverse stream of air is blown through the bag during collection shutdown, which re-moves the ash coating and channels it into a collection hopper. The other method involves collection of the ash on the outside of the bag. A high-pressure pulse of air is periodically forced down through the bag, shaking the ash from the bag and into the ash hopper.

Wet Scrubbers

These devises cause the ash to be mixed with water droplets in a high-velocity air stream. The ash-laden droplets are then collected in a down-stream scrubber demister section. Care must be taken in the disposal of the contaminated water, which will contain sulfuric and hydrochloric acid from the chemical combination of water and fly-ash. Also, additional care must be taken to assure the water is properly and completely removed from the flue gas. A wet scrubber has an advantage since additional heat is removed from the flue gas and can be recovered by exchangers for heating makeup water For comparison purposes, here are the cost differentiation factors between the various solid particulate collection systems, starting with the assumption that the mechanical collector is a factor of one:

Sulfur Dioxide Removal and Control

All coal and oil contain some sulfur. As a result, there is bound to be some amount of sulfur dioxide generated in the combustion process. Just how its emission is minimized depends on a number of available techniques.

Coal Benefication

Using washed coal is considered the best alternative for meeting sulfur regulations. Factors such as transportation, availability and price need to be considered. This practice is not as common as it used to be, given the availability of lower-sulfur coal.

Wet Nonregenerative Scrubbers

These systems can operate in a “throwaway” mode, where the sulfur dioxide gas reacts with a chemical, such as limestone, and the combined compound is disposed of or sold for gypsum. With additional processing, the elemental sulfur can be separated and made available for sale. Solids and pH levels are continuously monitored from a slipstream takeoff.

Wet Regenerative System

These scrubbers substantially speed up the collection process. However, their effectiveness requires the use of expensive sodium hydroxide or sodium carbonate, which require recovery systems. A major benefit, however, is the lack of sol-ids buildup, scaling, or critical pH control.

Dry Scrubbers

Here the flue gas is combined with chemicals in a water-based spray. The heat in the flue gas dries up the moisture, leaving a solid product, collectable in the baghouse. Critical elements in these systems include residence time in the chamber, flue gas temperature, which must be high enough to assure 100% moisture evaporation and adequate mixing of the chemical with the flue gas.

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