Many parts of the world are facing the triple challenge of providing secure energy to fuel economic growth at an affordable cost while minimizing the impact of energy production on the environment. Island nations especially struggle to address this trilemma, as renewable resources are usually limited and fossil fuels imported. Traditionally such distributed power plants have relied on liquid fuels and multiple open cycle reciprocating engines to provide both redundancy and the ability to load follow across a broad load range to maximize efficiency. This approach has created high electricity prices and significant negative environmental impact, especially that attributed to CO 2 , NO x , and SO x . With increasing natural gas production, the availability of Liquefied Petroleum Gas (LPG) has grown, and costs have fallen, allowing the potential to switch from fuel oils to LPG to reduce environmental impacts. Energy costs and environmental impact can be further reduced by using high efficiency Gas Turbine Combined Cycle plants with dry low emissions combustion technology. However, a further hurdle facing many locations is lack of the fresh water required for combined cycle operations. LPG-fuelled Gas Turbine Combined Cycle using Organic Rankine Cycle (ORC) technology can address all aspects of this energy trilemma. This paper reviews the conceptual design of a proposed 100MW distributed power plant for an island location, based on multiple LPG-fuelled gas turbines to follow load demand, with an ORC bottoming cycle to maximize efficiency.

Across the world, many people, especially in rural communities, still lack access to secure, affordable electricity supplies. Many countries also lack or have under-developed indigenous fossil fuel resources, or rely on environmentally unfriendly fuels such as coal or Heavy Fuel Oil. Many under-developed regions though are blessed with considerable agricultural resources, and well-suited to Distributed Power Generation, where smaller decentralized power plants are located close to the actual energy consumers. Distributed Power eliminates the need for an electricity transmission grid, or reduces the investment costs necessary to strengthen the grid system, and helps ensure stable, secure electricity to support local economic growth. Agricultural wastes can be used as a locally available feedstock to produce the energy required to electrify regions and stimulate economic growth. This paper examines the benefits of applying Poly-generation — the production of multiple products at a single location — and examines a proposed bio-refinery scheme to produce ethanol from agricultural waste. The ethanol production process produces a waste biogas, which can then be used in a high efficiency Cogeneration (or Combined Heat and Power) plant as a fuel for gas turbines to generate electricity and steam (heat), not just for the bio-refinery but also local industry and businesses. By creating a high value product (ethanol) along with a free fuel, the bio-refinery acts as an anchor plant to provide reliable, affordable electricity to the local community. As well as providing economic benefits, such a concept has multiple environmental benefits as regions and nations try to combine growth in energy demand with reduction in global greenhouse gas emissions: agricultural residues that would otherwise have decayed emitting methane and CO 2 into the atmosphere are used to create a high value product in ethanol, while using the biogas as a fuel displaces combustion of fossil fuels, reducing both combustion emissions and those associated with transportation of the fuel to the point of use.

Access to electricity is a key necessity in today’s World for economic growth and improvements in quality of life. However, the global challenge is addressing the so-called Energy Trilemma: how to provide secure, affordable electricity while minimizing the impact of power generation on the environment. The rapid growth in power generation from intermittent renewable sources, such as wind and photovoltaics, to address the environmental aspect has created additional challenges to meet the security of supply and affordable electricity aspects of this trilemma. Fossil fuels play a major role in supporting intermittent renewable power generation, rapidly providing the security of supply needed and ensuring grid stability. Globally diesel or other fuel oils are frequently used as the primary fuel or back-up fuel for fossil-fueled power generation plants at all scales, from a few kiloWatts to hundreds of MegaWatts, and helps provide millions of people with secure electricity supplies. But diesel is a high polluting fuel, emitting high levels of carbon dioxide (CO 2 ) per unit of fuel input compared to natural gas, as well as high levels of combustion contaminants that are potentially hazardous to the local environment and human health. Additionally, diesel can be a high cost fuel in many countries, with imports consuming significant portions of sometimes scarce foreign currency reserves. Most observers consider that natural gas is the ‘fuel of choice’ for fossil power generation due to its reduced CO 2 emissions compared to coal and diesel. However, access to gas supplies cannot be guaranteed even with the increased availability of Liquefied Natural Gas (LNG) and Compressed Natural Gas (CNG). Additionally where natural gas is available, operators may opt for an interruptible gas supply contract which offers a lower tariff than a firm gas supply contract, therefore there is a need for a back-up fuel to ensure continuous power supplies. While traditionally diesel or Heavy Fuel Oil (HFO) has been used as fuel where gas is not available or as a back-up fuel, propane offers a cleaner and potentially lower cost alternative. This paper compares the potential economic, operational and environmental benefits of using propane as a fuel for gas turbine-based power plants or cogeneration plants.

Emissions reduction requirements lead to modification of the firing system to control NOx emission reduction, and/or the post combustion treatment of the flue gas to remove NOx, SO2 & particulates. It has also leads to installation of new renewable energy production systems. All of these measures are very expensive both in installation and operation costs, while utilities are looking for low cost options with a minimum impact on unit performance and reliability. Firing of methanol and its blends with other liquid fuels, in comparison with other renewable sources, is one of the main alternatives for meeting this target. Methanol is a clean burning fuel that is made from non-petroleum energy sources such as natural gas, coal, biomass and carbon dioxide. Using CO2 for methanol production leads to reducing of greenhouse gas emissions so that methanol can actually be called as enviro fuel. The blending of methanol with light fuel oil is one of the quickest and cheapest means for both replacing costly petroleum energy consumed in the existing power generation fleet and reducing emissions that lead to air pollution such as nitric oxides, carbon monoxide, air toxics and PM. Hence, methanol is a good candidate as an alternative fuel for power generation, since it is liquid and has several physical and combustion properties similar to fuel oil. For this reason, this study is aimed to evaluate gas turbine performance and emissions characteristics for different blends of methanol and light fuel oil. The results obtained from simulation of different light fuel blends were compared to those of actual burning. In this study we experimented with methanol fractions (from 0 to 100 % by heat) at different GT loads and found that the methanol and light fuel oil blends enabled us to significantly reduce NOx emissions with increasing of the methanol fraction. SO2 emissions were also reduced according to the methanol heat fraction. The final blend ratio optimization should be based upon environmental requirements and fuel price. CO emissions are slightly higher than the required level. Based on performed tests, the main reason for CO formation is high excess air, especially at partial loads and as a result of low combustion temperature (this conclusion is right for any fuel and its blends). In order to reduce CO emissions, proper air /fuel control is necessary (IGV, IBH etc). This conclusion is very important for conceptual design of gas turbines in general and particularly for GT conversion to methanol firing. Firing of methanol and its blends had no impact on GT performance and provides safe operation. The computer simulations provide support for these experimental findings and conclusions. The results of the performed tests analysis indicate that methanol firing is a potentially promising low cost technology for emissions’ reduction and may be implemented in existing and new gas turbines.

Traditional methods for reducing emissions, by modification of the firing system to control the mixing of fuel and air, the reduction of flame temperatures (for NOx emission reduction), and/or the post combustion treatment of the flue gas to remove NOx, SO 2 particulates are very expensive. Hence, before implementation of expensive measures for the reduction of emissions, it is necessary to evaluate all low cost alternatives, such as burning alternative fuels and mixing it with other liquid fuels. Methanol offers these advantages, being a derivative of natural gas which is partly de-linked from oil, and is a clean burning fuel. Existing experience [1, 2] has shown that with inexpensive and minimal system modifications, methanol is easily fired and is fully feasible as an alternative fuel. Relative to heavy fuel and light fuel, methanol can achieve improved efficiency and lower NOx emissions due to the lower flame temperature and nitrogen content. Since methanol contains no sulfur, there are no SO 2 emissions. The clean burning characteristics of methanol are expected to lead to clean pressure parts and lower maintenance costs. In this paper we present results for the specific 10 ton/hr industrial boiler (results of the burning of methanol in large utility boilers we presented in our earlier publications) located at DOR Chemicals. In this study we experimented with methanol fractions (from 0 to 100 % by heat) at different boiler loads and found that the methanol and heavy fuel oil mixtures enabled us to meet the commonly accepted emissions limit for NOx with zero CO emissions. SO 2 emissions were also reduced according to methanol heat fraction. Methanol burning leads to a more than 10 % reduction of CO 2 . It should be noted that in our tests we used a special patented mixing device (the “Fuel Activation Device – FAD) developed by Turbulent Energy Inc. for preparing premixed or in-line blends. The results show that more than 50% of NOx reduction is achieved when light fuel oil is replaced by methanol and more than an 80% reduction when heavy fuel oil is replaced by methanol. For all boiler operation modes 100% of combustion efficiency is achieved. Methanol and liquid fuel blends lead to significant reduction of emissions depending on the methanol heat fraction. Burning of a blend of liquid fuel with water leads to a significant reduction of NOx. In addition, the usage of the FAD in our tests had positive effects on boiler efficiency improvement both for LFO and methanol firing. In this paper we also present the study of methanol and diesel fuel burning in diesel engine. It should be noted that blends were prepared by a using special mixing device developed by Turbulent Energy Inc. The performance of the engine using blended fuel compared to the performance of the engine with diesel fuel. It was also found that with using the blend one may achieve a more than 75 % reduction of NOx emissions when diesel oil is replaced by 20% methanol. Methanol and diesel oil co-firing leads to a reduction of SO 2 emissions depending on the heat fraction of methanol. We believe that the conclusions of the work presented are general and can be applied to any other industrial, utility boiler, or diesel engine as well.

The aim of the present study is to numerically investigate the combustion characteristics of Heavy Fuel Oil (HFO) and NOx emissions inside a calciner used in cement industry. The calciner is a furnace placed before the rotary Kiln its main objectives are the reduction of CO 2 emissions and air pollutions while enhancing the cement quality through separating the calcination and clinkering processes. In order to conduct the present investigations the calciner at CEMEX Egypt Cement Company was considered and real dimensions and operating conditions were applied. The combustion model was based on the conserved scalar (mixture fraction) and prescribed Probability Density Function (PDF) approach. The (RNG) k-ε turbulence model has been used. The HFO droplet trajectories were predicted by solving the momentum equations for the droplets using Lagrangian treatment. The radiation heat transfer equation was solved using P1 method. The formation of thermal NO x from molecular nitrogen was modeled according to the extended Zeldovich mechanism. The effects of varying the burner’s swirl number and viscosity grade on the combustion performance of HFO and the resulting NO x emissions were considered. The burner’s swirl number influences the mixing rate of air and fuel. A small swirl number ≤ 0.6 is not desired as it elongates the flame; increases flue gases temperatures and increases the NOx emissions inside the calciner. A swirl number ≥ 0.6 is found optimal for good combustion characteristics and NOx emissions concentration. Meanwhile, it was found that the HFO viscosity has a significant effect on the injection velocity and must be considered as a function of temperature during the analysis as this will significantly affects the combustion characteristics.

Ameresco & Department of Energy Savannah River partnered together to install three biomass fueled energy plants. The main plant is a 20 megawatt steam power plant and the other two smaller plants are thermal heating plants. All three facilities are located on the Department of Energy Savannah River Site (SRS). These facilities were developed and financed under an Energy Savings Performance Contract (ESPC), which utilizes energy and operational savings to fund the capital investment and operations cost over the performance period. Ameresco was fully responsible for the design, installation, oversight, management, safety, environmental compliance, and continues to be responsible for the operations and maintenance of the Biomass Cogeneration Facility. This is the largest biomass facility installed under ESPC in the federal government. The facilities have the capacity to combust 385,000 tons of forest residue annually. In the first year alone, the energy and operation cost savings at SRS is in excess of $34 million. Clean biomass and bio-derived fuels (such as tire derived fuel and untreated pallets) is the primary fuel source for all of the new boilers. Biomass is used to fuel two steam boilers capable of producing 240,000 lb. /hr. of high-pressure steam and to power a steam turbine capable of generating up to 20 MW of electricity. The smaller thermal plants provide biomass-produced steam for the areas’ heating and industrial processes. These plants satisfy winter steam requirements for both domestic heat and process steam and is fueled solely with biomass wood chips, utilizing fuel oil as backup source of fuel. Key benefits of the SRS biomass project include: • Over 2,000,000 MBtu/yr. of thermal renewable energy production and a minimum of generation of 77,000,000 kWh of green power • Annual Energy Reductions of approximately 500,000 MBtu/yr. • No-cost Renewable Energy Credits retained by the DOE SR • Support of the South Carolina Biomass Council Goals • Decrease of water intake from the Savannah River by 1,400,000 kgal/yr., supporting water conservation efforts in the region • Reduction of 400 tons/yr. of Particulate Matter (PM) emissions • Reduction of 3,500 tons/yr. of Sulfur Dioxide emissions • Reduction of 100,000 tons/yr. of Carbon Dioxide emissions The smaller heating plants include the main boiler systems and live bottom trailer fuel storage. The Biomass Cogeneration Facility includes the biomass boiler systems, the steam turbine generation system, and the facility auxiliary systems as well as the site infrastructure within these boundaries. The Facility has been designed, built, and tested per industrial/commercial codes for cogeneration facilities. The main components of the Facility are listed below: • Fuel Yard – Material Unloading & Storage and Delivery System ○ Biomass Fuel Chip unloading system ○ Fuel Storage Area ○ Transfer conveyors ○ Fuel Screening System ○ Tire Derived Fuel Storage & Unloading Area ○ Whole Log Chipping System & Storage • Water Treatment System – Water treatment system to treat river water for use in boilers as well as cooling tower for condensing turbine • Boiler Systems – (2) Boiler Island from metering bin, water side and flue gas side, pollution control devices and stacks • Chemical Treatment System – Chemical skids, injection skids for cooling tower and boiler treatment • Steam Turbine Generator System & Turbine Cooling System – (1) steam turbine and generator & Cooling Tower with cooling tower pumps • Emergency Generator System – (1) back diesel generator • Plant Control System – Master SCADA system which integrates all systems and balance of plant equipment I/O into one control system

Alaska village survival is threatened by the high cost of imported fuels for heating, electricity generation, and vehicles. During Winter 2007–8, the price per gallon of heating oil and diesel generation fuel exceeded $8 in many villages. Many villagers were forced to move to Anchorage or Fairbanks. Although indigenous renewable energy (RE) resources may be adequate to supply a community’s total annual energy needs, the innate intermittent and seasonal output of the renewables — except geothermal, where available, which may be considered “baseload” — requires large-scale, low-cost energy storage to provide an annually-firm energy supply. Anhydrous ammonia, NH 3 , is the most attractive, carbon-free fuel for this purpose at Alaska village scale, because of its 17.8% mass hydrogen content and its high energy density as a low-pressure liquid, suitable for storage in inexpensive mild steel tanks. NH 3 may be synthesized directly from renewable-source electricity, water, and atmospheric nitrogen (N 2 ) via solid state ammonia synthesis (SSAS), a new process to be pioneered in Alaska.

Over the past years there has been a dramatic increase in the regulatory requirements for low emissions from both new and existing utility boilers and gas turbines. Traditional methods of reducing NO x emissions, such as: modification of the firing system; and/or post combustion treatment of the flue gas to remove NO x ; are very expensive. One of the attractive alternative fuels for combustion in the utility boilers and stationary gas turbines may be methanol. Using methanol has become an important solution for emissions compliance due to their unique constituents and combustion characteristics. Methanol may be referred to as enviro fuel. The clean burning characteristics of methanol are expected to lead to clean pressure parts, turbine blades and lower maintenance than with fuel oil. Here, we present results of the Israel Electric Corporation (IEC) for specific 140 MWe unit consisting of tangential fired pressurized boiler designed by Combustion Engineering Inc by using the co-firing of methanol with heavy fuel oil and FT4C TWIN PAC 50 MWe GT designed by Pratt & Whitney by using the full methanol firing. The experiments performed for gas turbine tested different GT loads during methanol and LFO firing. The results presented here clearly show that with minor low cost fuel system retrofit methanol firing leads to significant NO x , SO2 and particulates emission reduction. NO x emissions were reduced more than 75% and are equal 75 mg/dNm3 at 15% O2. SO2 emissions were reduced to zero with methanol firing. Particulate emissions vary from 1.3 to 1.6 mg/dNm3 at 15% O2 with methanol firing, while with LFO this parameter was 13–37 mg/dNm3 at 15% O2. The experiments performed for the boiler tested different methanol fractions of the total boiler heat capacity (from 33% to 50% heat), at different boiler loads. The results presented here show that NO x , SO2 and particulate emissions were reduced more than 20%, 35% and 40% accordingly. We believe that the conclusions of the present work are general and can be applied to other boilers and gas turbines as well.

In 2010, the APT Company of the USA joined with the TRANSFUEL Company of Ecuador to demonstrate the operation of Fuel Oil Emulsion (FOE) Fuel in the process boilers of the El Café plant in Guayaquil, Ecuador. The intent of the joint venture was to prove the efficacy of FOE Fuels in decreasing boiler emissions and increasing plant operational efficiency. FOE Fuels reduced NOx Emissions by 13%, PM Emissions by 29% and increased Boiler Efficiency on the order of 3.5% This paper presents the full record of this successful FOE Demonstration Program.

A computational model is developed in order to investigate pollutant emissions from power plant boilers to the atmosphere. A well-known method of pollutant reduction is the modification of the combustion conditions to prevent their formation, and 3D computational fluid dynamics (CFD) codes provide an effective tool for the analysis of the combustion process. In this paper CFD calculations were performed to analyze the effect of the amount of combustion air on the production and emission of nitrogen oxides, one of the main pollutants produced during the combustion process. For this analysis the appropriate modeling of the chemical and physical phenomena involved is important, because the production and transport of pollutant species strongly depend on the flow and temperature distributions in the furnace. Two case studies are presented: a pulverized coal-firing tangential boiler and a fuel-oil frontal boiler. The CFD calculations adopt a 3D-formulation of the mean flow equations in combination with the standard high-Reynolds-number k-ε turbulence model. The model domain consists of the whole boiler, from the burner nozzles up to the exit of the economizer. Due to their complex geometrical features and computational limitations bank tubes are not modeled individually, but are grouped in a total volume. A porous media region approach is then undertaken to model gas flow and heat transfer in each heat exchanger. Model validation is a difficult task due to the lack of available data from commercial utilities. Validation has been done using routinely measured global parameters. Relatively good agreement is obtained. Results show that increasing the amount of air reduce nitrogen oxides formation for the case of the tangential boiler, however for the frontal boiler case this behavior is not as evident. These results demonstrate that CFD simulations are a viable tool to study the effect some combustion parameters have on the production of pollutants. CFD results may help to establish trends that, in turn, may help to reduce pollutant emissions from power plant boilers.

Diesel fuel oil storage tanks are critical components for safety of nuclear power plants. Proper functioning of the emergency diesel generators during an earthquake depends on the fuel oil supplied from the storage tank. Failure of the tank, nozzles or fuel pipes can result in contamination and/or leakage of the fuel. The allowable stress limits and design charts for above ground tanks, which are provided in the ASME Boiler and Pressure Vessel Code for a pressure vessel, are occasionally adopted in the design of underground tanks. However, the analytical methodology for evaluation of stresses in the buried tanks requires detailed analysis different from that for a typical pressure vessel. Soil-structure and fluid-structure interaction effects need to be considered in the analysis for simulation of the actual static and seismic loads. Therefore, advanced simulation techniques and finite element analysis tools have been used by several researchers to evaluate buried tanks. Simple, but acceptably accurate techniques for comprehensive evaluation of underground storage tanks have not been established. This study presents simplified evaluation techniques for a diesel fuel storage tank using fundamental concepts. The diesel fuel oil storage tanks considered here are cylindrical and oriented with their axes in the horizontal direction. The static overburden and seismic pressures cause ovaling of the tank and generate significant bending stresses, which are not addressed in the pressure vessel design approach. The simplified tank evaluation proposed here includes the ovaling effect under static overburden, seismic and sloshing loads. Earthquake induced stresses in hoop and longitudinal directions are calculated using the free field approach and the classical Housner Method is employed in the sloshing analysis. Allowable stress and buckling of the tank wall are checked against corresponding criteria.

Reduction of both atomizing steam and particulate emissions were investigated in a 350 MW e utility boiler. A residual fuel oil was dispersed as a fine mist into the furnace with sixteen atomizers of internal turbulent chamber type. The existing atomizers were replaced by Y-jet type atomizers. To do this, full scale prototypes were designed and tested in a cold model rig using mineral oil as the fuel and compressed air as the atomizing medium. The oil droplet size distribution was measured from a single port of each prototype by using a Malvern particle sizer. The prototype to be tested in the power station was selected based on the smallest oil droplets produced along with lower compressed air consumption. In the power station, the burners were modified to install the new design of Y-jet atomizers. Field tests were conducted at 50, 75 and 100% load. Atomizing steam was measured, as well as particulate emissions and the furnace exist flue gas temperature. With the Y-jet atomizers, the atomizing steam was reduced 55% with respect to the original atomizers; the unburned carbon particles were reduced by a maximum of 50%, the furnace exit gas temperature was similar between the two type of atomizers and no side effects were observed in the boiler.

In the early twenty-first century, emphasis on fossil fuel emission reductions was focused on gaseous emissions. NOx emissions were recognized as precursors of smog and as such adversely affected the quality of life. Lately, emphasis on emission reductions has shifted to solid emissions. Particulates are recognized as health hazards that contribute to respiratory ailments. Fossil fuel combustion — so fundamental to the nation’s economy — unfortunately produces both emissions. Thus, the development of after-treatment technologies to treat fossil fuel combustion was pursued. Imposition of after-treatment technology proved costly from both application and maintenance aspects. In some instances, introduction of after-treatment technology caused a decrease in fuel efficiency. In view of the foregoing, it is important to note that there is a technology that REDUCES gaseous AND solid emissions of liquid fossil fuels. Furthermore, this technology can INCREASE fuel efficiency. The technology that can deliver this “triple-crown” of dual emission reduction and enhanced fuel efficiency is EMULSIFIED FUEL TECHNOLOGY (EFT). In this paper, we consider the constitution, production and characteristics of Emulsified Fuels. Then we consider their combustion and the environmental benefits that can accrue to their utilization. Finally, we consider past applications of EFT and the future markets for this intriguing technology.

A study was carried out to find out the cause of premature plugging of air heaters of a 350 MW e oil fired boiler. The unit burnt a heavy fuel oil number 6, with both high levels of sulfur (3.75%) and asphaltenes (16.2%), as well as high viscosity (555 SSF at 50°C) and API gravity of 11.2. Particle concentration at the furnace exit and at the stack were measured, also flue gas analyses were performed at the same sites. In the furnace were employed water cooled probes of six meters in length which allowed traversing 70% of its width. In addition, the oil droplet size distribution from an atomizer was measured with a Malver Particle Sizer. Cold condition using simulating fluids were taken in this analysis. Also, the unburned carbon particles size distribution, both from the furnace exit and from the stack, was performed with a particle Malver Sizer. The atomizer produced large oil drops, 5.7% by volume larger than 300 micron size, which were considered as promoters of unburned carbon. The concentration of carbon particles in the stack was 60% of that of the furnace exit. Furthermore, the particles from the stack were of smaller size (95% <150 μm) than those of the furnace (89% <150 μm). Deposition of carbon particles in the internal component of the boiler, mainly in the air heaters, was the cause of this finding. To solve the premature plugging of the air heaters of this oil fired boiler, the atomizers should be modified to reduce at a minimum level the oil drops larger than 200 micron size.

Currently there is a need for a model to estimate mass emissions of atmospheric pollutants at the exit of the stacks of thermal power plants that operate under a variable regime of electric power generation based on the variables that typically are monitored during the operation of the plants. The recommended alternative to calculate the mass emissions of pollutants is based on the experimental measurements of pollutant concentration, velocity and temperature at the exit of the stack. This alternative is expensive and cumbersome to implement. Alternatively the US EPA emission factors can be used. However, the emission factors require modifications to account for the type of fuel, the technology used to control emissions, maintenance of the equipment, and the local environmental conditions. As a solution, this paper presents a model to estimate emissions of atmospheric pollutants in thermal power plants based on the variables that are continuously monitored during the operation of most of the thermal power plants in Mexico such as fuel chemical composition, fuel consumption, air to fuel ratio of the combustion process, and mean boiler temperature. The proposed model was calibrated by continuously measuring all the variables included in the three models during one week of operation of a 2.2 GW thermal power plant located in the continental area of the Gulf of Mexico. This plant has six units of generation that operate with fuel oil and one with natural gas. Results obtained from the three methodologies described before were compared. It was concluded that the NOx, SOx and CO results of the proposed model follow closely the results obtained using the measurements of concentration, velocity and temperature at the exit of the stack method. It was also found that the results of the emission factors methodology require to be adjusted to include the particular operating conditions of each unit of electricity generation.

The most popular method of controlling sulfur dioxide (SO 2 ) emissions in a steam turbine power plant is a flue gas desulfurization (FGD) process that uses lime/limestone scrubbing. Another relatively newer FGD technology is to use seawater as a scrubbing medium to absorb SO 2 by utilizing the alkalinity present in seawater. This seawater scrubbing FGD process is viable and attractive when a sufficient quantity of seawater is available as a spent cooling water within reasonable proximity to the FGD scrubber. In this process the SO 2 gas in the flue gas is absorbed by seawater in an absorber and subsequently oxidized to sulfate by additional seawater. The benefits of the seawater FGD process over the lime/limestone process and other processes are; 1) The process does not require reagents for scrubbing as only seawater and air are needed, thereby reducing the plant operating cost significantly, and 2) No solid waste and sludge are generated, eliminating waste disposal, resulting in substantial cost savings and increasing plant operating reliability. This paper reviews the thermodynamic aspects of the SO 2 and seawater system, basic process principles and chemistry, major unit operations consisting of absorption, oxidation and neutralization, plant operation and performance, cost estimates for a typical seawater FGD plant, and pertinent environmental issues and impacts. In addition, the paper presents the major design features of a seawater FGD scrubber for the 130 MW oil fired steam turbine power plant that is under construction in Madinat Yanbu Al-Sinaiyah, Saudi Arabia. The scrubber with the power plant designed for burning heavy fuel oil containing 4% sulfur by weight, is designed to reduce the SO 2 level in flue gas to 425 ng/J from 1,957 ng/J.