Efficient and Reliable Use of the "Bottom of the Barrel" for Steam/Power Generation

Paper from the AFRC 2014 conference titled Efficient and Reliable Use of the "Bottom of the Barrel" for Steam/Power Generation by B. Schrecengost.

Heavy Fuel Oil is an important resource for power generation in the Middle East. However, the physical and chemical properties of HFO present challenges to the power plant designer and operator. This paper will discuss modern innovations in designs of steam power plants for oil firing, including: • Application of modern supercritical boiler designs to increase efficiency • State of the art NOx and corrosion control to lower environmental impacts • Designs for utilization of heavier oils such as Vacuum Residual Oil (VRO) to increase flexibility • Application of oxy firing to achieve carbon capture. Working in close partnership with Saudi oil/gas producers, electricity producers and university researchers, power plant designers have identified the needs of the oil-fired power generation market to update designs for the fuel and generation challenges of the 21st century. These challenges include the need for highly efficient boiler operation while utilizing lower quality liquid fuels that are increasingly common as refiners extract more of the valuable light fractions. Modern designs must keep emissions of NOx, SOx and particulates low and operate efficiently with those lower quality liquid fuels. This paper will focus on three aspects of modern steam power plant design: 1. Supercritical steam cycles in comparison to subcritical designs including efficiency gains and life-cycle cost savings, 2. Control of NOx and SOx emissions through modern low NOx firing designs, selective catalytic reduction (SCR) where necessary, and additives for SO3 and corrosion control, and 3. The unique challenges in particulate control and fuel handling associated with firing very heavy oils such as Vacuum Residual Oil (VRO). Finally, future options for carbon capture, sequestration and utilization (CCSU) will be briefly discussed.

2014 AFRC Industrial Combustion Symposium Hyatt Regency Hotel, Houston, TX, September 7-10 *Corresponding Author: Tel.: [phone] Fax: [phone] E-mail address: [e-mail] Efficient and Reliable Use of the "Bottom of the Barrel" for Steam / Power Generation Robert Schrecengosta*, Ed Henrya, Tracy Midgleya, Wei Zhanga, Olaf Stallmannb, Frank Vernettic aALSTOM Power, Inc., 200 Great Pond Drive, Windsor, CT 06095 USA bALSTOM Carbon Capture GmbH, Lorenz-Schott-Straße 4, 55252 Mainz-Kastel, Germany cALSTOM Power Systems SA, 3 Avenue des Trois Chênes, 90018 Belfort Cedex, France 90000 Abstract Heavy fuel oil is an important resource for power generation in the Middle East. Unlike the US, where oil-fired sources contribute less than 1% to total power generation, the Kingdom of Saudi Arabia (KSA) generates 65% of its electricity from oil-fired sources. However, the physical and chemical properties of heavy residual oils present challenges to the power plant designer and operator. This paper will discuss modern innovations in designs of steam power plants for oil firing, including: • Application of modern supercritical boiler designs to increase efficiency • State-of-the-art NOx and corrosion control to lower environmental impacts • Designs for utilization of heavier fuel oils such as Oil Heavy Residue (OHR) to increase flexibility Working in close partnership with Saudi oil/gas producers, electricity producers and university researchers, Alstom power plant designers support the needs of the oil-fired power generation market to update designs for the fuel and generation challenges of the 21st century. These challenges include the need for highly efficient boiler operation while utilizing lower quality liquid fuels becoming increasingly common as refiners extract more of the valuable light fractions. Modern designs must keep emissions of NOx, SOx and particulates within regulatory limits and operate efficiently with those lower quality liquid fuels. This paper will focus on three aspects of modern steam power plant design: 1. Supercritical steam cycles in comparison to subcritical designs including efficiency gains and life-cycle cost savings, 2014 AFRC Industrial Combustion Symposium Hyatt Regency Hotel, Houston, TX, September 7-10 2 2. Control of NOx and SOx emissions through modern low NOx firing designs, selective catalytic reduction (SCR) where necessary, and additives for SO3 and corrosion control, 3. The unique challenges in particulate control and fuel handling associated with firing very heavy fuel oils such as Oil Heavy Residue (OHR) Introduction In its 2012 World Energy Outlook, the IEA estimates that worldwide electricity demand will increase by over 70% by 2035. In this scenario, IEA estimates that fossil fuels will represent slightly less than 60% of power generation by 2035. [1] Improvements in generation efficiency reduce consumption of scarce fossil fuel resources and minimize impacts to the environment, including emissions of carbon dioxide (CO2). The power generation industry has steadily made improvements in generation efficiency as technology has evolved and it is expected that over time this trend shall continue. Today, most new coal units built are supercritical (SC) and ultra-supercritical (USC) units, and the future outlook is for plants with advanced ultra-supercritical (AUSC) design conditions. Heavy oil fuels often have higher sulfur content than coal as well as the trace metal vanadium which the coals used for power generation typically do not contain. These unique factors increase corrosion rates for oil-fired boilers in comparison to coal-fired units, and the higher furnace tube metal temperatures associated with higher steam cycles further increase the potential for fireside (or high temperature) corrosion. In response, power plant designs for oil-fired units include the requirement for the use of fuel additives to control corrosion; additionally, steam conditions are typically limited to 540°C or less in the SH/RH elements. Oil-fired units must also meet environmental limits for emissions of particulate, NOx and SO2 while minimizing corrosion in the furnace and back pass. Meeting these requirements is becoming more challenging for oil-fired power generation units because refiners are moving to technologies to increase the production of high value petroleum products, resulting in an increase in the amount of lower-grade by-products that are being considered for use as fuel in power generation. One such refinery by-product is Oil Heavy Residue (OHR). OHR is the fraction of petroleum that does not evaporate under vacuum in the distillation process of refining, and represents the bottom product from the vacuum distillation 2014 AFRC Industrial Combustion Symposium Hyatt Regency Hotel, Houston, TX, September 7-10 3 column, the so-called "bottom of the barrel." Traditionally, these remaining residues might be used as the binder for asphalt, or potentially be converted to petcoke. Alternatively, they can also be upgraded, through energy and capital intensive processes to synthetic crude and other refined products. Due to the expected increase in required generation capacity in the Kingdom of Saudi Arabia, OHR is being considered as a future fuel source for power generation. In contrast to the current refinery by-product heavy fuel oil (HFO) used in suspension firing for power generation, the composition of OHR and its general poor quality make it a difficult fuel for use in existing boiler designs. In particular, OHR has a very high viscosity, as well as greater percentages of sulfur, nitrogen, carbon residue and heavy metals such as vanadium and nickel. As a result, OHR must be heated to high temperatures (much higher than HFO) in order to reduce its viscosity enough to allow pumping and atomization. Therefore, the use of OHR requires a specially designed fuel handling system, one that is not commonly found in current oil-fired steam plants. OHR fuels also have higher sulfur and asphaltene content, resulting in higher SOx and particulate emissions. Consequently, the design of the Air Quality Control Systems (AQCS) must accommodate these increased emissions control requirements. Asphaltenes will typically increase the flue gas particulate loading, especially of difficult to collect "cenospheres" (relatively large-size carbon particles). As a result, the firing and particulate control systems must be designed to address these environmental concerns. Supercritical Steam Cycles with Heavy Residual Oils Supercritical steam cycles have steam conditions above the supercritical point of 220.6 bar and have been used around the world for coal and natural gas fired power generation units over the past 40 years. Supercritical (SC) technology is an established and proven technology with over 500 SC units operating worldwide and achieving similar reliability and availability with that of subcritical units. These units typically have main steam pressures of 225-270 bar, with SH temperatures of 540-565°C and RH temperatures of 540-586°C. [2] Increasingly, the move to achieve higher efficiency and thus reduce fuel consumption and emissions of carbon dioxide per MW of electricity produced has driven SC technology to 2014 AFRC Industrial Combustion Symposium advanced conditions. Ferritic alloys have allowed boiler designers to increase steam conditions to ultra-supercritical (USC) steam temperatures in the range of 600° construction over the past ten years on advanced metals characteristics and manufacturing techniques to further increase steam temperatures to ultra-supercritical (AUSC) steam conditions delivered over 350 SC and USC The rationale for increasing steam conditions can be seen in subcritical steam conditions, current Middle East are 4.6% higher in efficiency. give an additional 2.1% gain in plant Figure 1 - Efficiency Increase with Current units employing SC technology are mostly coal been recent experience with oil-fired units, but this experience has been limited to conditions of 250 bar or less at SH/RH power production to USC steam conditions increase in unit efficiency as shown in critical reference case. Hyatt Regency Hotel, Houston, TX, September 7 erritic parameters, with pressures of 270-310 bar and SH/RH °C to 620°C. The USC cycles have been adopted to further increase efficiency and reduce emissions is underway around the world the 700°C to 760°C range, referred to as advanced conditions. Alstom and its licensees have designed and power generation units. Figure 1. Compared to a baseline of SC cycles used on oil-fired power generation units in the 6% Extension to state of the art USC parameters will efficiency. SC and USC Steam Cycles coal-fired power production units. There has temperatures of 540°C/540°C. Extension of oil would result in significant fuel savings due to the Figure 2, where fuel savings are normaliz 7-10 4 for new emissions. Research , igned SC steam oil-fired normalized to the sub- 2014 AFRC Industrial Combustion Symposium Figure 2 - Annual Fuel Oil Usage Reduction with SC and USC Steam Conditions Recent boiler designs at SC steam conditions of 250 bar 870,000 barrels annually versus subcritical steam conditions of increase to SC steam conditions of 250 bar / 565°C / 565°C or USC steam conditions of 275 bar / 620°C / 620°C would result in additional annual fuel savings of 245,000 to 42 plants normalized to the same net power output The effect of these fuel savings plus the capital costs of the various unit designs on levelized cost of electricity (LCoE) is shown in conditions of 250 bar / 540°C / 540°C resu conditions of 175 bar / 540°C / 540°C. Further increase to SC steam conditions of 250 bar / 565°C / 565°C or USC steam conditions of 275 bar / 620°C / 620°C would result in LCoE savings of 10% and 13%, respectively, versus subcri 540°C. Hyatt Regency Hotel, Houston, TX, September 7 / 540°C / 540°C result in savings of over 175 bar / 540°C / 420,000 barrels output. Figure 3. Recent oil-fired boiler designs at SC steam result in LCoE savings of 8% versus subcritical steam subcritical steam conditions of 175 bar / 540°C / 7-10 5 540°C. Further 0,000 for tical 2014 AFRC Industrial Combustion Symposium Figure 3 - Levelized Cost of Electricity Reduction with SC and USC Steam Conditions Heavy Oil Control of NOx and SOx Emissions and Corrosion with Heavy Residual Oils NOx Emissions Modern low-NOx firing systems can required with primary measures a selective catalytic reduction (SCR) or selective nonca current NOx regulatory requirement for oil firing in This is often achieved with a low NOx designs integrated with one or two levels of separated Figure 4. Hyatt Regency Hotel, Houston, TX, September 7 Oil-Fired Steam Power Plants often achieve the regulatory levels of NOx emissions and without additional post-combustion controls such as noncatalytic reduction (SNCR) systems. The the Middle East is typically 2 low-NOx burner design, such as the Alstom tangentially over fire air (SOFA) 7-10 6 in alytic 220 mg/Nm3. tangentially-fired low- , as shown in 2014 AFRC Industrial Combustion Symposium Figure 4 - Low-NOx Tangential The effect of OFA quantity on NOx emissions is shown in developed based on testing performed on operating p Kingdom of Saudi Arabia. The results production unit able to meet the NOx emissions regulatory limit with just a low NOx firing system and over fire air. Figure 5 - Effect of OFA Quantity on NOx Emissions with HFO Firing Hyatt Regency Hotel, Houston, TX, September 7 Firing System and Windbox Arrangement for Oil Figure 5. These data have been power generation units firing HFO in the show an example of a commercially operating power 7-10 7 Oil-firing . ower 2014 AFRC Industrial Combustion Symposium Hyatt Regency Hotel, Houston, TX, September 7-10 8 If required, an SCR system can also be included in the design. The SCR system utilizes a catalyst and reductant (a diluted mixture of ammonia gas in air) to disassociate NOx to nitrogen gas and water vapor. The primary catalytic process reactions are as follows: 4 + 43 + 2[ ] → 42 + 62 22 + 43 + 2[ ]−> 32 + 62 Since NOx is ninety five percent (95%) NO in the flue gas stream, the first reaction dominates. Major critical variables that affect the percentage of NOx removal are the reaction temperature, the flue gas volumetric flow rate, the inlet gas velocity and the molar ratio of ammonia to inlet NOx. Power plant designers can achieve over 90% NOx reductions through careful consideration of the design variables listed above. [3] OHR fuel and ash properties can affect the SCR system design in several ways. The high sulfur content and high SO3 levels entering the SCR reactors require higher minimum operating allowable temperatures (typically 340-350°C). This could require an economizer bypass to maintain flue gas temperature entering the SCR above the minimum allowable operating temperature at lower loads. Additionally, the fine sticky particulate, alkali metals and unburned carbon from OHR firing can plug and/or deteriorate catalyst activity over time. Steam or compressed air rake blowers are recommended instead of sonic horns for particulate removal from the catalyst layers. SOx Emissions The control of SOx to the regulatory limit is accomplished by flue gas treatment with reagents (usually containing calcium and/or magnesium) in flue gas scrubbing systems. The current SOx regulatory requirement for oil firing in the Middle East is typically 220 mg/Nm3. Depending on the plant's location, either a sea water flue gas desulfurization (SWFGD) or a lime-based dry scrubbing technology may be the economic choice. The SWFGD process consists of two systems. One system is the gas handling unit where the flue gas is cleaned, and if necessary reheated before discharge to the stack. The other system is the Seawater Treatment Plant, where the absorber effluent is neutralized before discharge to the sea. The major advantage of the SWFGD system compared to traditional Limestone FGD systems is that there is no handling of slurry, so there is no need for slurry pumps, tanks or mixers. This 2014 AFRC Industrial Combustion Symposium Hyatt Regency Hotel, Houston, TX, September 7-10 9 results in lower investment, operating and maintenance costs as well as an increased reliability. Another benefit is the supply of reagent and disposal of by-products are avoided. [4] The major advantages of the SWFGD system are: • Low consumption of water to the absorber, together with a lower head loss, resulting in low power consumption. • Superior experience in seawater treatment, meeting the performance guarantees in water quality parameters such as dissolved oxygen, pH and level of chemical oxygen demand due to unoxidized SO2. Variations on spray drying technology may be an alternative to the SWFGD where hydrated lime can be acquired at feasible cost and perhaps where no sea water is available. One such system is a semi-dry technology integrating several sub functionalities into one unit: • Gas absorption of HCl, HF and SO2 • Removal of dioxins and heavy metals • Removal of particulate This Alstom dry scrubbing system is called NID™ and consists of a fabric filter with an integrated reactor and mixer humidifier. The reagent, in the form of recycled dust, is supplied to the bottom of the reactor. Water in the dust evaporates quickly and the flue gas temperature is then reduced to the temperature required for efficient absorption, normally 10-20°C above saturation. In practice the temperature is in the range of 65-75°C. [5] In a conventional wet FGD process, the lime is supplied to the flue gas as slurry, whereas in the NID™ variation of spray drying technology the recycled dust (which contains active lime) has a water concentration of only a few per cent. Note that sufficient amount of water is added to reduce the flue gas temperature to the required level. Both of these technologies are well suited for application to higher sulfur, lower quality residual fuel oils. For a SWFGD, the size of the equipment will increase to maintain SO2 emissions below the regulatory limit. For a dry scrubbing system, the amount of reagent consumed and ash generated will increase to maintain SO2 emissions below the regulatory limit. A lifecycle analysis is needed to determine the most economic choice for any given fuel and plant location. 2014 AFRC Industrial Combustion Symposium Hyatt Regency Hotel, Houston, TX, September 7-10 10 Corrosion Fireside corrosion occurs at the high temperatures encountered in the firing zone and convective pass of oil-fired boilers. It is an increasing concern with heavy residual fuels because of increasing levels of sulfur, sodium and vanadium as refiners extract more of the valuable light fractions. Oil-fired power generators rely on additives to control both high temperature and low temperature corrosion. For corrosion control, the most commonly used fuel additives contain magnesium, either as MgO or Mg(OH)2, and typically in oil dispersed (organic) forms. Magnesium-based additives control high temperature corrosion by reacting with vanadium. Vanadium forms the salt vanadium pentoxide (V2O5) during the combustion process of residual fuel oils. This salt melts at ~650ºC and sticks to boiler tube metal surfaces in the high temperature sections. Once attached to the tube surface, the substance has the potential to corrode. [6] Magnesium oxide reacts with V2O5 to form magnesium vanadate (MgV2O4). This is a salt with a much higher melting temperature that exceeds furnace tube metal temperatures. The ash is now in a soft, powdery and extremely friable form, never sticks to the tube surface and harmlessly exits the boiler. In this manner, additives are used to control high temperature corrosion. The additive feed rate is based on the fuel oil flow, sulfur, sodium, and vanadium concentrations in the fuel. Higher levels of SO3 are also formed by the presence of V2O5, which catalyzes the oxidation of SO2 to SO3 and leads to increased levels of sulfuric acid, H2SO4. [7] This acid can be very damaging to equipment in sections of the plant with flue gas temperatures at or below the acid dew point, such as the cold end of the air preheater and ductwork beyond that point. Corrosion in this region is often called low temperature corrosion. The formation of MgV2O4 consumes V2O5 and reduces the potential of increased SO3 formation. Magnesium oxide also reduces the levels of SO3 by reacting with it to form the salt magnesium sulfate (MgSO4). The additive effectively neutralizes sulfuric acid that would otherwise condense on the cooler parts of the air preheater. In this manner, the same additives are used to control high and low temperature corrosion. [7] Extension of oil-fired power production to higher SC or even USC steam conditions is desirable for generation efficiency considerations, but the higher furnace tube metal temperatures associated with higher steam cycles increase the potential for corrosion. 2014 AFRC Industrial Combustion Symposium Boiler manufacturers often utilize metal temperatures and alternative materials of construction that have better corrosion resistance at higher temperatures. Convective arrangement alternatives include parallel flow exchanger arrangements, placement of the finishing SH and RH sections in furnace regions with colder flue gas, and locating SH and RH platens all of these alternate design considerations will increase the size of the convective heating surfaces in the Boiler manufacturers are also investigating the applicability of alternate materials of construction for the convective sections of oil in current commercially-available design alloys used in coal-fired USC design T23 and T24, as well as the austenitic alloys 304H alloys for the different convective sections and expected tube metal temperatures for SC steam conditions of 242 bar and SH and RH temperatures of 565°C are shown in Once suitable alloys have been identified for higher SC or USC steam conditions applications in oil-fired units, the economic tradeoffs between alternate design arrangements and alternate materials of construction must be determined to develop a competitive HFO or OHR at the higher steam conditions. Figure 6 - Example of Oil-Fired Boiler Hyatt Regency Hotel, Houston, TX, September 7 alternate boiler convective pass arrangements to limit tube cement after the radiative section of the furnace. ll limit tube metal temperature, they will boiler. oil-fired boilers with higher SC or USC steam condi designs. Boiler manufacturers are performing testing with designs. Alloys of interest include the ferritic alloys T91, T92, 304H, Super 304H, 347H and HR3C. Figure ce design for units firing Materials for Steam at 242 bar, 565°C, 565°C 7-10 11 onvective heat While also conditions than used . . Potential 6. 2014 AFRC Industrial Combustion Symposium Hyatt Regency Hotel, Houston, TX, September 7-10 12 Firing Oil Heavy Residue Particulate emissions from oil-fired units are influenced by fuel quality and operational effects. The fuel quality with the greatest effect on the generation of particulate emissions is the asphaltene content of the residual oil. In fact, particulate mass emissions have been determined to be roughly proportional to the asphaltene concentration in the fuel. [8] Operational effects on particulate mass emissions from oil-fired units include: • Atomization quality, which determines the particulate size distribution and amount of large particulates. o Atomization is a function of fuel viscosity - heavy fuel oil has to be heated to reduce viscosity. Typical viscosity required is 15-30 cSt. A challenge is to heat the OHR while keeping all heat exchanger equipment surfaces below the coking temperature where fuel would foul the surfaces. • Longer residence time at high temperature and increased excess air will reduce particulate loading. • For low-NOx combustion, improved SOFA air mixing and increased SOFA residence time will reduce particulate loading. [8] When considering typical global NOx regulations, excess air and SOFA utilization must be optimized to meet the NOx emissions limit; operational improvements to reduce particulate emissions are largely available from improvements in atomization quality. One difference between firing HFO and OHR is the much higher viscosity of OHR. Heating of OHR to proper fuel temperatures is very important for pumping and handling as well as for good atomization which is essential for good combustion. Development of fuel heating options with increased heating capacity and precise fuel oil temperature control will be needed for commercial applications. The viscosity-temperature relationship for OHR and HFO-380 is shown in Figure 7. HFO-380 is a grade of HFO that is blended with lighter fractions to produce a fuel with a viscosity of 380 cSt at 50°C. In general, heavy fuels oils need a viscosity of 1000-2000 cSt for good pumping characteristics and a viscosity of 15-30 cSt for good atomization and combustion. The figure shows that HFO-380 is pumpable at 40°C and can be atomized with heating to only 100-120°C. 2014 AFRC Industrial Combustion Symposium In contrast, the three OHR examples must be heated to 80 to 200-230°C to reach the viscosity required Figure 7 - HFO and The OHR temperatures required for good Consequently, the fuel oil heating system in a commercial unit would have complexity than current designs for HFO close to the coking point for OHR heating system must supply fairly unifor to avoid "hot spots" where localized coking could occur in the fuel supply lines. Another difference between HFO and OHR fuels. The increased level of asphaltenes in carbon emissions in the form of cenospheres. particulate/unburned carbon emissions when result of incomplete combustion of the oil droplet char particle remaining after vaporization of the lighter hydrocarbons from the droplet. An illustration of the cenosphere formation mechanism is shown in Figure 8. almost entirely due to changes in unburned carbon in the form o Hyatt Regency Hotel, Houston, TX, September 7 xamples 80-125°C to be pumped successfully, and for good atomization. OHR Viscosity - Temperature Relationship fuel atomization are much higher than those for HFO. a higher capacity HFO-fired units. Additionally, the required temperatures are fuels. This is another design concern for OHR uniform heating to the fuel oil, and it must be OHR fuels is that asphaltenes are typically higher in the ed OHR can lead to much higher unburned It is known that asphaltene content influences firing heavy residual oils. [8] Cenospheres . Changes in particulate mass emissions for a given unit are of cenospheres. 7-10 13 and . OHR; the fuel oil well controlled ] are the e 2014 AFRC Industrial Combustion Symposium Figure 8 - Cenosphere Formation in Heavy Fuel Oil Combustion The effect of excess O2 levels on particulate mass l based on testing performed on operating power generation unit of Saudi Arabia. The diamonds are data points taken in the north economizer squares are from the south duct. levels are reduced. The relationship of excess O to be even stronger with OHR firing Figure 9 - Effect of Excess O One way to improve atomization quality with a given oil burner tip configuration is to increase the fuel preheat. The effect of fuel temperature mass loading is shown in Figure power generation units firing HFO particulate increase of up to 100% as fuel The relationship of fuel firing temperature and atomization in general on particulate mass loading is expected to be even stronger with Hyatt Regency Hotel, Houston, TX, September 7 loading is shown in Figure 9. These data are units firing HFO-380 in outlet duct and the The results show a particulate increase of 50-125 O2 levels on particulate mass loading is expected because of the higher asphaltene levels. O2 on Particulates with HFO Firing (and thus atomization quality) on particulate 10. These data are based on testing performed on operating HFO-380 in the Kingdom of Saudi Arabia. The results show a culate preheat temperature is reduced by as li OHR firing. 7-10 14 . the Kingdom 125% as excess O2 ittle as 20°C. 2014 AFRC Industrial Combustion Symposium Figure 10 - Effect of Fuel Temperature on Particulates with HFO Firing As mentioned previously, changes in particulate mass emissions for a given unit are almost entirely due to changes in unburned carbon in the form o cenospheres is related to the original droplet shows the range of cenospheres collected from the same commercially operating power generation unit in the Kingdom of is 60 μm, with a broad range of particle sizes related to the original atomization quality. Figure 11 - Example of Cenospheres from HFO Combustion Cenospheres are difficult for an electrostatic precipitator (ESP) to collect because hold an electrical charge well; furthermore, Hyatt Regency Hotel, Houston, TX, September 7 ly, of cenospheres. The size of the res size distribution of the atomized fuel oil. ingdom Saudi Arabia. The d50 (mean diameter) of the particles shown fficult ; they are light and often re-entrained into the flue gas 7-10 15 Figure 11 they do not 2014 AFRC Industrial Combustion Symposium Hyatt Regency Hotel, Houston, TX, September 7-10 16 stream even if they are initially collected on the ESP collection plates. Power plant designers compensate for increased particulate loading and cenospheres by increasing the ESP cross-sectional area to reduce particle velocities entering the ESP, increasing the specific collection area of the ESP collection plates, reducing rapping frequency to minimize the entrainment of the collected dust, and/or adding a flue gas conditioning system. One augmentation system used is the injection of ammonia which will improve cohesion of dust layers in the ESP and improve ESP performance for cenospheres, making it easier to collect the carbonaceous particulate. [9] Conclusions Refiners are increasingly using technologies to increase the production of high value petroleum products, resulting in a decrease in the quality of lower-grade by-products that are being considered for use as the design fuel in power generation. One example is Oil Heavy Residue or OHR, the bottom product from vacuum distillation and the so-called "bottom of the barrel." To continue the economic use of lower quality refinery by-products for power generation, power plant designers such as Alstom are integrating new and modified plant subsystems required to address the challenges of increased generation efficiency, control of emissions and fireside corrosion, and the future need to address global climate change concerns with CCSU. To maintain competitiveness with other power generation options, power plant designers need to extend steam conditions to higher SC or even current state of the art USC parameters and increase plant efficiency by up to 2%. Designers can limit corrosion potential at the higher steam conditions by using alternate SH/RH design arrangements to limit metal temperatures and alternate materials of construction for increased corrosion resistance in the SH/RH sections. Current technologies used by power plant designers for SO2 control are well suited for application to higher sulfur, lower quality residual fuel oils. For a SWFGD, the size of the equipment will increase to maintain SO2 emissions below the regulatory limit. For a dry scrubbing system, the amount of reagent consumed and particulate generated will increase to maintain SO2 emissions below the regulatory limit. A lifecycle analysis will determine the most economic tradeoff between capital and operating costs for any given fuel and plant location. 2014 AFRC Industrial Combustion Symposium Hyatt Regency Hotel, Houston, TX, September 7-10 17 Modern low-NOx firing systems can often achieve the regulatory levels of NOx emissions required without additional post-combustion controls, even with lower quality residual oils. The challenge for power plant designers is to maintain acceptable particulate emissions as the asphaltene content of the fuel increases, mainly by improving atomization quality. Improvement in atomization quality can be achieved by increasing fuel preheat temperature, increasing atomization steam flow, and burner tip design optimization to minimize particulate formation in the form of cenospheres. Power plant designers compensate for increased particulate loading and cenospheres by increasing the ESP cross-sectional area to reduce particle velocities entering the ESP, increasing the specific collection area of the ESP collection plates, reducing rapping frequency to minimize the entrainment of the collected dust, and/or adding a flue gas conditioning system. Alstom is a leading provider of power plant equipment, including turnkey power plants, and continues to advance the clean, efficient, and economic utilization of oil-based fuels as they continue to evolve, including those fuels that might be characterized as the "bottom of the barrel." 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