A Technical Overview Electricity Generation

Commercial Combustion-Based Technologies

Combustion technology choices available today for utility scale power generation include circulating fluidized bed (CFB) steam generators and pulverized coal (PC) steam generators utilizing air for combustion. Circulating fluidized beds are capable of burning a wide range of low-quality and low-cost fuels. The largest operating CFB today is 340 Megawatts (MW), although units up to 600 MW are being proposed as commercial offers.

Pulverized coal-fired boilers are available in capacities over 1000 MW and typically require better quality fuels.

Advanced Pulverized Coal Combustion (PC) Technology

Pulverized Coal Process Description

In a pulverized coal-fueled boiler, coal is dried and ground in grinding mills to face-powder fineness (less than  50 microns). It is transported pneumatically by air and injected through burners (fuel-air mixing devices) into the combustor. Coal particles burn in suspension and release heat, which is transferred to water tubes in the combustor walls and convective heating surfaces. This generates high temperature steam that is fed into a turbine generator set to produce electricity.

In pulverized coal firing, the residence time of the fuel in the combustor is relatively short, and fuel particles are not recirculated. Therefore, the design of the burners and of the combustor must accomplish the burnout of coal particles during about a two-second residence time, while maintaining a stable flame. Burner systems are also designed to minimize the formation of nitrogen oxides (NOX) within the combustor.

The principal combustible constituent in coal is carbon, with small amounts of hydrogen. In the combustion process, carbon and hydrogen compounds are burned to carbon dioxide (CO2) and water, releasing heat energy. Sulfur in coal is also combustible and contributes slightly to the heating value of the fuel; however, the product of burning sulfur is sulfur oxides, which must be captured before leaving the power plant. Noncombustible portions of coal create ash; a portion of the ash falls to the bottom of the furnace (termed bottom ash), while the majority (80 to 90%) leaves the furnace entrained in the flue gas.

Pulverized coal combustion is adaptable to a wide range of fuels and operating requirements and has proved to be highly reliable and cost-effective for power generation. Over 2 million MW of pulverized coal power plants have been operated globally.

After accomplishing transfer of heat energy to the steam cycle, exhaust flue gases from the PC combustor are cleaned in a combination of post combustion environmental controls. These environmental controls are described in detail in further sections. A schematic of a PC power plant is shown in Figure 1.1.

Fluidized Bed Combustion

Fluidized Bed Combustion Process Description

In a fluidized bed power plant, coal is crushed (rather than pulverized) to a small particle size and injected into   a combustor, where combustion takes place in a strongly agitated bed of fine fluidized solid particles. The term “fluidized bed’’ refers to the fact that coal (and typically a sorbent for sulfur capture) is held in suspension (fluidized) by an upward flow of primary air blown into the bottom of the furnace through nozzles and strongly agitated and mixed by secondary air injected through numerous ports on the furnace walls. Partially burned coal and sorbent is carried out of the top of the combustor by the air flow. At the outlet of the combustor, high-efficiency cyclones use centrifugal force to separate the solids from the hot air stream and recirculate them to the lower combustor.

This recirculation provides long particle residence times in the CFB combustor and allows combustion to take place at a lower temperature. The longer residence times increase the ability to efficiently burn high moisture, high ash, low-reactivity, and other hard-to-burn fuel such as anthracite, lignite, and waste coals and to burn a range of fuels with a given design.

CFB technology incorporates primary control of NOX and sulfur dioxide (SO2) emissions within the combustor. At CFB combustion temperatures, which are about half that of conventional boilers, thermal NOX is close to zero. The addition of fuel/air staging provides maximum total NOX emissions reduction. For sulfur control, a sorbent is fed into the combustor in combination with the fuel. The sorbent is fine-grained limestone, which is calcined in the combustor to form calcium oxide. This calcium oxide reacts with sulfur dioxide gas to form a solid, calcium sulfate. Depending on the fuel and site requirements, additional NOX and SO2 environmental controls can be added to the exhaust gases. With this combination of environmental controls, CFB technology provides an excellent option for low emissions and very fuel-flexible power generations.

CFB technology has been an active player in the power market for the last two decades. Today, over 50,000 MW of CFB plants are in operation worldwide.

Advanced Steam Cycles for Clean Coal Combustion

Improving power plant thermal efficiency will reduce CO2 emissions and conventional emissions such as SO2, NOX and particulate by an amount directly proportional to the efficiency improvement. Efficiency improvements have been achieved by operation at higher temperature and pressure steam conditions and by employing improved materials and plant designs. The efficiency of a power plant is the product of the efficiencies of its component parts. The historical evolutionary improvement of combustion-based plants is traced in Figure 1.2. As shown, steam cycle efficiency has an important effect upon the overall efficiency of the power plant.

As steam pressure and superheat temperature are increased above 225 atm (3308 psi) and 374.5°C (706°F), respectively, the steam becomes supercritical (SC); it does not produce a two phase mixture of water and steam but rather undergoes a gradual transition from water to vapor with corresponding changes in physical properties. In order to avoid unacceptably high moisture content of the expanding steam in the low pressure stages of the steam turbine, the steam, after partial expansion in the turbine, is taken back to the boiler to be reheated. Reheat, single or double, also serves to increase the cycle efficiency.

Pulverized coal fired supercritical steam cycles (PC/SC) have been in use since the1930s, but material developments during the last 20 years, and increased interest in the role of improved efficiency as a cost-effective means to reduce pollutant emission, resulted in an increased number of new PC/SC plants built around the world. After more than 40 years of operation, supercritical technology has evolved to designs that optimize the use of high temperatures and pressures and incorporate advancements such as sliding pressure operation. Over 275,000 MW of supercritical PC boilers are in operation worldwide.

Supercritical steam parameters of 250 bar 540°C (3526psi/1055°F) single or double reheat with efficiencies that can reach 43 to 44 % (LHV) (39 to 40% HHV) represent mature technology. These SC units have efficiencies two to four points higher than subcritical steam plants representing a relative 8 to 10% improvement in efficiency. Today, the first fleet of units with Ultra Supercritical (USC) steam parameters of 270 to 300 bar and 600/600°C (4350 psi, 1110°/1110°F) are successfully operating, resulting in efficiencies of >45% (LHV) (40 to 42% HHV), for bituminous coal-fired power plants. These “600°C” plants have been in service more than seven years, with excellent availability. USC steam plants in service or under construction during the last five years are listed in Figure 1.3.

Looking forward, advancements in materials are important to the continued evolution of steam cycles and higher efficiency units. Development programs are under way in the United States, Japan and Europe, including the THERMIE project in Europe and the Department of Energy/Ohio Cooperative Development Center project in the United States, which are expected to result in combustion plants that operate at efficiencies approaching 48% (HHV) (Figure 1.4). Advanced materials development will be critical to the success of this program.

Figure 1.5 summarizes the evolution of efficiency for supercritical PC units. It should be noted that commercial offerings for supercritical CFBs have been made in the last two years and that the first SCCFB units will be commissioned in the next 2 to 3 years.

The effect of plant efficiency upon CO2 emissions reduction is shown in Figure 1.6.

It is estimated that during the present decade 250 gigawatts (GW) of new coal-based capacity will be constructed. If more efficient SC technology is utilized instead of subcritical steam, CO2 emissions would be about 3.5 gigaton (Gt) less during the lifetime of those plants, even without installing a system to capture CO2 from the exhaust gases.

Environmental Control Systems for Combustion-Based Technologies

In all clean-coal technologies, whether combustion- or gasification-based, entrained ash and trace contaminants and acid gases must be removed from either the flue gas or syngas. Different processes are used to match the chemistry of the emissions and the pressure/temperature and nature of the gas stream.

PC/CFB plants can comply with tight environmental standards. A range of environmental controls are integrated into the combustion process (low NOX burners for PC, sorbent injection for CFB) or employed post combustion to clean flue gas. The following sections describe the state of the art for emissions controls for combustion technologies. In general, these environmental processes can be applied as retrofit to older units and designed into new units. In some cases, performance will be better on a new unit since the design can be optimized with the new plant.

Figure 1.7 illustrates the comprehensive manner in which combustion and post-combustion controls combine to minimize formation and maximize capture of emissions from clean-coal combustion.

Overview of Nitrogen Oxides

Nitrogen oxides are byproducts of the combustion of virtually all fossil fuels. The formation of NOX in the combustion process is a function of two reactions/sources—thermal NOX originates from the nitrogen found in  the air used for combustion, and fuel NOX originates from organically bound nitrogen found at varied levels in all coals. Control of NOX emissions is accomplished in PC/CFB units through a combination of in-furnace control of the combustion process and post-combustion reduction systems.

Combustion NOX Control

Advanced low NOX PC combustion systems, widely used today in utility and industrial boilers, provide dramatic reductions in NOX emissions in a safe, efficient manner. These systems have been retrofitted to many existing units and are reducing NOX emissions to levels that in some cases rival the most modern units. The challenges  are considerable, given that the older units were not built with any thought of adding low NOX systems in the future. Low NOX combustion systems can reduce NOX emissions by up to 80% from uncontrolled levels, with minimal impact on boiler operation, and they do so while regularly exceeding 99% efficiency in fuel utilization. Low NOX firing systems are standard equipment on new PC units.

Advanced low NOX systems start with fuel preparation that consistently provides the necessary coal fineness while providing uniform fuel flow to the multiple burners. Low NOX burners form the centerpiece of the system, and are designed and arranged to safely initiate combustion and control the process to minimize NOX.

An overfire air (OFA) system supplies the remaining air to complete combustion while minimizing emissions of NOX and unburned combustibles. Distributed control systems (DCS) manage all aspects of fuel preparation, air flow measurement and distribution, and flame safety and also monitor emissions. Cutting-edge diagnostic and control techniques, using neural networks and chaos theory, assist operators in maintaining performance at peak levels.

For pulverized coal units, uncontrolled NOX emissions from older conventional combustion systems typically range from 0.4 to 1.6 lb/106 Btu, dependent on the original system designs. Retrofitting of low NOX PC combustion systems is capable of reducing NOx down to 0.15 to 0.5 lb/106 Btu exiting the combustor; the performance is highly dependent on the fuel and the ability to modify the existing boiler design. The goal of the DOE’s low NOX burner program is to develop technologies for existing plants with a NOX emission rate of 0.15 lb/106 Btu by 2007 and 0.10 lb/106 Btu by 2010, while achieving a levelized cost savings of at least 25% compared to state-of-the-art selective catalytic reduction (SCR) control technology.

New plants which can be designed for optimized reduction of NOX in the firing systems which will achieve combustor outlet levels at the lower end of this range and designs are in demonstration to drive combustor outlet NOX levels to 0.1 lb/MMBtu.

Combustion NOX Control Costs

The installed cost of a low NOX combustion system retrofit on a coal-fired unit is in the range of $7 to $15/kW to achieve NOX reductions of 20 to 70%. Installation of low NOX firing systems is standard procedure on new units, and the cost is embedded in the firing system cost of the new unit design.

The industry continues to aggressively develop improvements to low NOX burner technology to lessen the NOX reduction requirements of the post-combustion NOX control equipment (selective catalytic reduction), which can significantly reduce capital and operating costs.

Post Combustion NOX Control — SCR and SNCR

Advanced PC/CFB plants utilize a combination of combustion and/or post-combustion control for high levels of NOX reduction. PC plants generally combine low NOX firing with selective catalytic reduction (SCR) to reduce NOX emissions, while CFB units utilize selective non-catalytic reduction (SNCR).

SCR systems use a catalyst and a reductant (typically ammonia) to dissociate NOX to harmless nitrogen and water. The SCR catalytic-reactor chamber is located at the outlet of the combustor, prior to the air heater inlet. Ammonia is injected upstream of the SCR; the ammonia/flue gas mixture enters the reactor, where the catalyst reaction is completed. SCR technology is capable of reducing NOX emissions entering the system by 80 to 90%. SCR technology has been applied to coal-fired boilers since the 1970s; installations are successfully in operation in Japan, Europe and the United States.

Depending on the fuel, CFB units may also incorporate post combustion NOX control. Typically CFB would utilize a chemical process called selective non-catalytic reduction (SNCR) to reduce NOX. In SNCR, a reagent (either ammonia or urea) is injected in the flue gas and reacts with the NOX to form nitrogen and ammonia.

No catalyst is used, and it is necessary to design the injection to provide for adequate residence time, good mixing of the reagent with the flue gas and temperature, and a suitable temperature window (1600°–2100°F) to drive the reaction. SNCR is capable of reducing NOX emissions entering the system by 70 to 90% and is a proven and reliable technology that was first applied commercially in 1974.

SOX Overview

All coals contain sulfur (S), which, during combustion, is released and reacts with oxygen (O2) to form sulfur dioxide, SO2. A small fraction, 0.5 to 1.5%, of the SO2 will react further with O2 to form sulfur trioxide (SO3). If an SCR is installed for NOx control, the catalyst may result in an additional 0.5 to 1.0% oxidation of SO2 to SO3. Both SO2 and SO3 are precursors to acid rain.

The most prevalent technologies for SO2 reduction in the U.S. power generation market are wet scrubbing, or wet flue gas desulfurization (WFGD) and spray dryer absorption (SDA). Wet scrubbers can easily achieve 98% to over 99% SO2 removal efficiency on any type of coal. Other technologies that have been employed to a minor extent include dry sorbent injection and dry fluidized-bed scrubbers.

All recent, new coal-fired generating plants include either WFGD or SDA technologies for SOX emissions control. The technology selection is dependent on the coal characteristics, the emission limit requirements, and site-specific factors, which may include restrictions on water availability and space limitations. WFGD is typically used when the expected range of coal sulfur content will exceed approximately 1.5%. However, SDA technology has been applied across the full range of coal ranks.

The U.S. utility industry is experiencing a surge of WFGD system retrofits at existing generating stations in response to Clean Air Interstate Rule (CAIR) and other state or federal legislation. Approximately 38,000 MW of WFGD systems are currently in various stages of design and construction. WFGD systems dominate the coal-fired utility industry with approximately 80 to 85% of the total installed SO2 emissions control systems.

SDA technology has been selected for emissions control on more than 3,500 MW of new coal-fired generators completed in the last five years or currently under construction, as well as more than 1,500 MW of retrofit installations. The SDA technology consumes significantly less water than WFGD and is often a choice where water usage is restricted.

Technical Description: Wet Scrubbers (WFGD)

Wet scrubbers are large vessels in which the flue gas from the combustion process is contacted with a reagent.  The reagent is typically limestone or lime mixed with water to form a slurry. The reagent is added to the scrubber in a reaction tank located at the bottom of the scrubber. Slurry from the reaction tank is pumped to a spray zone and sprayed into the gas inside the scrubber. This slurry is a combination of reaction products, fresh reagent and inert material. The SO2 is absorbed into the slurry, reacts with the reagent, and forms a solid reaction product. A portion of the recirculated slurry is pumped to a dewatering system where the slurry is concentrated to 50 to 90% solids. The water is returned to the scrubber. The most common reagent for wet scrubbing is limestone, although there are a number of units that use lime or magnesium-enriched lime.

Peformance: WFGD

Wet scrubbers can easily achieve 98% to over 99% SO2 removal efficiency on any type of coal.

Direction of Technology Development: WFGD

The development of wet scrubbers is in the optimization stage to drive incremental removal to more than 99% and to reduce capital and operating cost. This includes developing methods for reduction in power and reagent consumption. Also, better methods for reducing moisture carryover and lowering the filterable particulate leaving the scrubber are important.

There is work in developing multi-emissions control systems that optimize the design of post-combustion controls and integrate the capture processes for NOX, particulate, SO2 and mercury. In addition, innovations in wet scrubbing include a design that uses the air stream used for forced oxidation to develop the recirculated flow of slurry in the scrubber. Also, work is being done on high-velocity designs to reduce the size of WFGD.

Technical Description: Spray Dryer Absorption (SDA)

SDA differs from WFGD in that it does not completely quench and saturate the flue gas. A reagent slurry is sprayed into the reaction chamber at a controlled flow rate that quenches the gas to about 30°F above the saturation temperature. An atomizer is used to break up the reagent slurry into fine drops to enhance SO2 removal and drying of the slurry. The water carrying the reagent slurry is evaporated leaving a dry product. The gas then flows to a fabric filter (FF) or electrostatic precipitators (ESP) for removal of the reaction products and fly ash.

There is also significant SO2 and other acid gas removal in the fabric filter due to the reaction of SO2 with the alkaline cake on the filter bags. Fresh lime slurry is mixed with a portion of the fly ash and reaction products captured in the particulate collector downstream of the SDA to form the reagent slurry.

SDA is considered best available control technology (BACT) for sub-bituminous coal-fired generating stations. State-of-the-art application of the technology involves one or more SDA modules each with a single, high- capacity atomizer to introduce the reagent slurry to the flue gas followed by a pulse-jet fabric filter for collection of the solid byproduct. Demonstrated long-term availability and reliability of the system have eliminated the need for including spare-module capacity in the design.

SDA technology has also been applied as a polishing scrubber following CFBs to achieve overall SO2 emissions reduction of 98 to 99%. Retrofit of SDA/FF systems on existing boilers is a cost-effective means to achieve significant emissions reduction.

Performance: SDA

Performance guarantees for SDA systems are typically in the range of 93 to 95% SO2 removal for coals with up to 1.5% sulfur content. Higher removal efficiencies have been guaranteed and demonstrated in practice. An SDA/FF system with a fabric filter can typically achieve >95% removal of H2SO4 with 0.004 lb/MMBtu as a typical emission limit. Emission limits for the acid gases HCl and HF as well as trace metals are also typically provided.

Direction of Technology Development: SDA

SDA is also a mature technology for SO2 emissions control. Technology development efforts are focused on integrating operating experiences from existing installations to:

• extend maintenance intervals by introducing new wear materials and process design features;
• reduce reagent consumption by enhancing process monitoring and optimizing lime slaking;
• enhance operating flexibility to respond to process upsets;
• enhance maintenance access; and
• optimize trace element and acid gas emission control performance.

Development efforts are also in progress to extend the capacity of the SDA modules and reagent slurry atomizers to treat higher flue gas flows in single spray chambers. Expansion of beneficial byproduct use applications is another ongoing development need.

H2SO4 Emission Control

The catalyst used in the selective catalytic reduction (SCR) technology for nitrogen oxides control oxidizes a small fraction of sulfur dioxide in the flue gas to SO3. The extent of this oxidation depends on the catalyst formulation and SCR operating conditions. Gas-phase SO3 and sulfuric acid, upon being quenched in plant equipment (e.g., air preheater and wet scrubber), turn into fine acidic mist, which can cause increased plume opacity and undesirable emissions.

An SDA followed by fabric filter provides for high-efficiency H2SO4 emissions control (+95% typically).

H2SO4 removal in wet scrubbers typically falls in the range of 30 to 60%; however, removal efficiencies as low  as 15% and as high as 75% have been achieved. R&D efforts are under way to gain a better understanding of the parameters for H2SO4 removal in wet scrubbers.

There are a number of emerging technologies that involve injection of dry reagent or slurry containing reagents into the gas path from the economizer inlet to the inlet of the wet scrubber. Reagent is typically injected in two or more locations. Typical reagents are sodium- or magnesium-based. Testing indicates that the acid removal increases when using slurry vs. using dry reagent feed. Some users report nearly 90% reduction of SO3/H2SO4.

The technology is not developed to the point where it is commercially bid and backed by performance guarantees.

Performance: WFGD

Wet scrubbers can easily achieve 98% to over 99% SO2 removal efficiency on any type of coal.

Direction of Technology Development: H2SO4 Emission Control

A variety of technologies are now being investigated to control SO3 and H2SO4 cost effectively. Reagent injection for control of SO3 and H2SO4 emissions is an area in which significant R&D efforts are under way. Work is being done to develop a better understanding of H2SO4 removal in the wet scrubber.

Particulate Control

Particulate Overview

All coals contain ash, and during the combustion process various forms of particulate, including vaporous products, are formed. The solid particulate is removed from the flue gas using either electrostatic precipitators or high-efficiency fabric filters. Many of the vaporous products can be removed by pretreatment methods that convert the vaporous products into solid particulate upstream of the particulate control. Mercury, for example, is removed using this pretreatment method by the addition of activated carbon.

Electrostatic Precipitators

Overview

Wet and dry electrostatic precipitators (ESPs) are effective devices for the removal of solid or condensed particulate matter and are proven, reliable subsystems for the utility customer.

In an ESP,  particulate-laden flue gas enters the ESP,  where electrons discharged by the discharge electrode system electrostatically charge the particulate. The charged particles are attracted to the positive grounded collecting surfaces of the ESP. The main difference in the wet ESP and the dry ESP is the method of removing  the trapped particle out of the system for disposal. In the dry ESP, the trapped particle is dislodged by mechanical rapping and drops in the ESP hoppers and is removed by using an ash removal system. In a wet ESP, the trapped particle is water-washed, and then the wash water and particulate is routed to the WFGD system and neutralized.

Performance: Wet ESP

The current particulate issue of interest is limiting fine particulate emission (under 2.5 microns) from coal-fired utility stacks. Plants that burn medium- to high-sulfur coals will be adding wet flue gas desulfurization systems on units with existing selective catalytic reduction systems. This will add to the particulate issue, as the mist formed in the scrubber contributes both to fine particulate emissions and stack appearance. Several plants have already experienced visible plumes from these emissions. Fine particulate emissions are also perceived as a health issue. Other hazardous air pollutants may become regulated, and the removal of these pollutants will become a major issue. Wet electrostatic precipitators (wet ESPs) are now being proposed on new boiler projects burning medium- to high-sulfur fuels to mitigate poor stack appearance, to limit acid mist emissions, and to limit fine particulate emissions.

Wet ESPs have successfully served industrial processes for almost 100 years. Cumulative experience gained over the past century is being employed to lower all particulate emissions from modern utility boilers.

As the wet ESP is designed to capture submicron particles, it can be designed to achieve 90 to 95% reduction in PM2.5 (particulate matter). The wet ESP has an added benefit of removing the same or a slightly higher percentage of other fine particulates. It is an excellent polishing device for collection of both solid PM2.5 and condensed particulate formed in the wet FGD system. The wet ESP is also an excellent collector of any remaining PM10 particulate.

Direction of Technology Development: Wet ESP

Wet ESP performance based on requirements for the near future is not an issue. Wet ESP technology   development will be cost-centered. Savings on capital investment may be realized by minimizing use of  expensive alloys (since alloy costs are unpredictable in today’s market) and novel arrangements. Parasitic power may be minimized by additional efforts to mitigate space charge either by redesign or alternate arrangements, and processes could substantially reduce unit size and cost on today’s projects.

Performance: Dry ESP

Dry electrostatic precipitators (dry ESPs) have been the workhorse of the utility industry for removal of solid particulate since the 1950s. Dry ESP development came from utility customer requirements to reduce emissions on existing installations, while keeping capital costs at a minimum. The dry ESP is an excellent device for removal of PM10 particulate from the boiler flue gases. It is a relatively good device for removal of solid PM2.5 particulate on some coals.

Future employment of this technology on retrofit projects will depend on utilities evaluation of capital cost versus operating costs of competing technologies. However, new testing methodologies need to be developed to attain repeatable results for the emission levels being required in today’s air permits.

Direction of Technology Development: Dry ESP

Today, the technology has evolved by work related to performance enhancements such as wider plate spacing, better discharge electrodes, digital controls and newly developed power supplies. Integration of ESPs with other technologies such as the particle agglomerator is also under consideration. Studies of the effects of unburned carbon on removal efficiency are under way to help this technology perform at its maximum level. The evolution of key dry ESP components such as collecting electrodes, discharge electrodes, wider plate spacing and more effective rapping systems has also improved the reliability of this technology. New technologies or improved technologies such as agglomerators and new power supplies could further enhance dry ESP performance. These enhancements appear to be more cost-competitive than replacement with a new particulate collector. On new projects, careful evaluation of the complete air quality system requirements will be necessary when selecting the primary particulate collector.

Fabric Filters

Technical Description

Fabric filters are particulate collectors that treat combustion flue gas by directing the gas through the filter media. The fabric filter is installed after the air heater as a particulate removal device. The fabric filter may be installed after a dry scrubber or pretreatment device and serves as a multi-pollutant removal device. Solid particulate is captured on the surface of the filter media. The collected particulate is dislodged from the filter media during the cleaning cycle. The dislodged particulate drops into the fabric filter hoppers for removal using the ash removal system. Some applications reuse the collected particulate as a recycled product to enhance the dry scrubber lime utilization.

The U.S. utility industry is favoring pulsejet technology today over reverse gas fabric filters in most coal-fired applications. Worldwide pulsejet has been the preferred fabric filter technology for more than a decade.

Advancements in fabric filter cleaning capabilities have resulted in smaller fabric filters that are being used in new and retrofit applications. In fact, there is a growing trend in the industry to convert the older undersized precipitators into high-efficiency fabric filters.

Performance

Fabric filters are the particulate collector of choice for most coal-fired applications. On low-sulfur coals, the fabric filter is coupled with dry scrubber technology and serves as a multi-pollutant control device. On medium- to high-sulfur applications fabric filters are being applied on new units as the primary particulate control device. Only on medium- to high-sulfur coals is the fabric filter less cost-effective than an electrostatic precipitator.

Many utilities are choosing the fabric filter over the electrostatic precipitators to ensure fuel flexibility and to keep down mercury-removal costs. The fabric filter is an excellent collector for both PM10 and PM2.5 filterable particulate relative to comparably sized precipitators.

Direction of Technology Development

The power industry is moving from the electrostatic precipitator particulate collector to fabric filter collectors for the majority of new installations. Air quality monitoring and opacity concerns are becoming a public issue, and the industry is responding to these issues with high-efficiency fabric filters.

This shift from precipitators to fabric filters has created a new research focus in the industry for advancements of filter media. Filter media development concentrates on restructuring, blending and coating of existing materials. Membrane-coated filter media are being developed by suppliers worldwide. Specialty filters supplied in cartridge form are commercially available, but much more development is needed. Alternative materials are being developed to improve temperature resistance and increase efficiency. Advancements in cleaning techniques are allowing for more efficient use of filter media including longer bags, which translates into fewer plan area requirements. Electrically enhanced pretreatment of filter media is one of the many advances under development.

Mercury Control

Mercury Overview

Current studies of mercury deposition in the United States indicate that 70% comes from natural sources and non-U.S. manmade emissions. Those non-U.S. anthropogenic emissions originate primarily from China and the rest of Asia. Before March 2005, coal-fired power plants were the largest unregulated anthropogenic source of domestic mercury emissions. However, they still account for less than 1% of global mercury emissions.

In 2005, the Environmental Protection Agency (EPA) proposed to reduce emissions of mercury from U.S. plants through the Clean Air Mercury Rule (CAMR), a two-phase cap-and-trade program. This program is integrated closely with other recent regulations requiring stricter sulfur dioxide (SO2) and nitrogen oxides (NOX) emission reductions called Clean Air Interstate Rule (CAIR). The CAMR establishes a nationwide cap-and-trade program  that will be implemented in two phases and applies to both existing and new plants. The first phase of control begins in 2010 with a 38-ton mercury emissions cap based on “co-benefit” reductions achieved through stricter SO2 and NOX removals. The second phase of control requires a 15-ton mercury emissions cap beginning in 2018. It has been estimated that U.S. coal-fired power plants currently emit approximately 48 tons of mercury per year. As a result, the CAMR requires an overall average reduction in mercury emissions of approximately 69% to meet the Phase II emissions cap.

In the following discussion, the term “co-benefit capture” is defined as utilizing existing environmental equipment, or equipment to be installed for future non-mercury regulation, to capture mercury. The term “active capture” is defined as installation of new equipment for the express purpose of capturing mercury.

Co-Benefit Mercury Control

Due to the large capital investments required of CAIR plants, it makes sense to take full advantage of co-benefit mercury control. Previous testing has demonstrated that various degrees of mercury co-benefit control are achieved by existing conventional air pollution control devices (APCD) installed for removing NOX, SO2 and particulate matter (PM) from coal-fired power plant combustion flue gas. The capture of mercury across existing APCDs

can vary significantly based on coal properties, flyash properties (including unburned carbon), specific APCD configurations, and other factors, with the level of control ranging from 0% to more than 90%. The most favorable conditions occur in plants firing bituminous coal, with installed selective catalytic reduction (SCR) and wet flue   gas desulfurization (WFGD), which may capture as much as 80% with no additional operations and maintenance (O&M) cost. Further R&D investments will be required to fully understand, and be able to accurately predict, co- benefit capture of mercury.

Other co-benefit mercury control technologies are being tested to enhance mercury capture for plants equipped with wet FGD systems. These FGD-related technologies include: 1) coal and flue gas chemical additives and fixed-bed catalysts to increase levels of oxidized mercury in the combustion flue gas; and 2) wet FGD chemical additives to promote mercury capture and prevent re-emission of previously captured mercury from the FGD absorber vessel. The DOE is funding additional research on all of these promising mercury control technologies so that coal-fired power plant operators eventually have a suite of control options available in order to cost effectively comply with the CAMR.

Active Capture Mercury Control

To date, use of activated carbon injection (ACI) has been the most effective near-term mercury control technology. Normally, powdered activated carbon (PAC) is injected directly upstream of the particulate control device (either an ESP or FF) which then captures the adsorbed mercury/PAC and other particulates from the combustion flue gas. Short-term field testing of ACI has been relatively successful, but additional longer-term results will be required before it can be considered to be a commercial technology for coal-fired power plants. There are issues such as the erosion/corrosion effect of long-term use of PAC (or any other injected sorbent or additive) as well as an increase in carbon content for plants that sell their fly ash or gypsum that might adversely affect its sale and lead to increased disposal costs.

Field testing has begun on a number of promising approaches to enhance ACI mercury capture performance for low-rank coal applications, including: 1) the use of chemically treated PACs that compensate for low chlorine concentrations in the combustion flue gas, and 2) coal and flue gas chemical additives that promote mercury oxidation. In order to secure the long-range operability of the existing power generation fleet, it is necessary to continue development of these advanced technologies.

Coal Combustion Products

The production of concrete and cement-like building materials is among the many beneficial reuses of coal combustion products. The use of Coal Combustion Products (CCPs) provides a direct economic benefit to the United States of more than $2.2 billion annually and a total economic value of nearly $4.5 billion each year. These findings are from a recent study published by the American Coal Council (ACC) and authored by Andy Stewart (Power Products Engineering). “The Value of CCPs: An Economic Assessment of CCP Utilization for the U.S. Economy,” details the economic value of CCPs, including:

• avoided cost of disposal
• direct income to utilities
• offsets to raw material production
• revenues to marketing companies
• transportation income
• support industries
• research
• federal and state tax revenues

CCPs, created when coal is burned in the generation of electricity, are the third-largest mineral resource produced in the United States.

In 2003, more than 128 million tons (mt) of CCPs were produced in the United States, predominantly fly ash, which accounted for nearly 60% of CCP production. Of the 128 mt of CCPs produced in 2003, 34 mt were utilized in value-added applications, such as cement and concrete products, highway pavement, soil stabilization and construction bedding, manufactured products and agriculture, among others. The production of CCPs has consistently outpaced utilization for the past 35 years, representing significant untapped market potential.

Future Economic Opportunity

The 94 mt of CCPs that were not utilized in 2003 were disposed of or deposited in landfills—a costly and inefficient use of land. According to the ACC study, in 2003 industry spent more than $560 million to dispose of CCPs. The cost savings of beneficial reuse—in other words, the avoided cost of disposal—totaled nearly $200 million in 2003. In addition to providing significant cost savings over landfill deposits, beneficial reuse programs produce better, more durable products and help lower the cost of electricity. This, in turn, leads to greater economic growth and prosperity, which enhances our nation’s ability to steward the environment.

Integrated Gasification Combined Cycle (IGCC)

Gasification of coal is a process that occurs when coal is reacted with an oxidizer to produce a fuel-rich product. Principal reactants are coal, oxygen, steam, carbon dioxide and hydrogen, while desired products are usually carbon monoxide, hydrogen and methane.

In its simplest form, coal is gasified with either oxygen or air. The resulting synthesis gas, or syngas, consisting primarily of hydrogen and carbon monoxide, is cooled, cleaned and fired in a gas turbine. The hot exhaust from the gas turbine passes through a heat recovery steam generator where it produces steam that drives a steam turbine. Power is produced from both the gas and steam turbine-generators. By removing the emission-forming constituents from the syngas under pressure prior to combustion in the power block, an IGCC power plant can meet stringent emission standards.

There are many variations on this basic IGCC framework, especially in the degree of integration. The general consensus among IGCC plant designers is that the preferred design is one in which the air separation unit derives part of its air supply from the gas turbine compressor and a part from a separate air compressor. Since prior studies have generally concluded that 25 to 50% air integration is an optimum range, the case study in this  section has been developed on that basis.

Three major types of gasification systems are used today: moving bed, fluidized bed and entrained flow. Pressurized gasification is preferred to avoid large auxiliary power losses for compression of the syngas. Most gasification processes currently in use or planned for IGCC applications are oxygen-blown instead of air-blown technology. This results in the production of a higher heating value syngas. In addition, since the nitrogen has been removed from the gas stream in an oxygen-blown gasifier, a lower volume of syngas is produced, which results in a reduction in the size of the equipment. High-pressure, oxygen-blown gasification also provides advantages when CO2 capture is considered.

Only oxygen-blown gasification has been successfully demonstrated for IGCC. Oxygen-blown gasification avoids the large gas (nitrogen) flows and very large downstream equipment sizes and costs that air-blown gasification would otherwise impose. However, the tradeoff is that an expensive cryogenic oxygen plant is required.

Pressurized oxygen-blown gasification reduces equipment sizes and enables the delivery of syngas at the specified fuel pressure required by cooling towers (CTs). Commercially, gasification pressures in IGCC range from about 400 psi to 1,000 psi depending on the process. Current entrained-flow gasification reactors have capacities of about 2000 to 2500 standard tons per day (st/d) of good quality coal. Larger coal sizes are required as coal quality decreases. While somewhat larger gasifier capacities may be possible, two gasifiers might be required for a very low-quality coal to match the syngas energy output of a single gasifier with a high-quality coal.

The gasification process also includes downstream cooling of the raw syngas in a waste heat boiler or by a water quench step. Saturated steam generated in the waste heat boiler is routed to the heat recovery steam generator of the combined cycle where it is superheated and used to augment steam turbine power generation. The steam required for gasification is also supplied from the steam circuit. Cyclones and/or ceramic, sintered metal hot filter and water scrubbing are employed for particulates removal. Water scrubbing also removes ammonia (NH3), hydrogen cyanide (HCN) and hydrogen chloride (HCl) from the syngas. Following cooling and particulates removal, the sulfur constituents of the syngas are removed in a gas treating plant.

The overall IGCC plant efficiency is also partly determined by the gasification process and configuration selected (heat recovery and quench). The recovery of heat from the hot raw syngas in a waste heat boiler enables a higher efficiency than water quenching of the raw syngas. However, syngas cooling adds significantly to the capital cost of gasification. Syngas heat recovery is an option for all of the gasification processes.

The predominant and preferred gasification processes for good quality solid feedstocks are Shell, General Electric (GE) and ConocoPhillips. Gas entrained-flow processes, as they operate at high temperatures, achieve good carbon conversion and enable higher mass throughputs than other processes. Some entrained-flow gasification processes are also suitable for low-rank fuels, such as lignites.

Entrained-flow gasifiers that operate in the higher-temperature slagging regions have been selected for the majority of IGCC project applications. These include the coal/water-slurry–fed processes of GE. A major advantage of the high-temperature entrained-flow gasifiers is that they avoid tar formation and its related problems. The high reaction rate also allows single gasifiers to be built with large gas outputs sufficient to fuel large commercial gas turbines. Recent studies have shown that a spare gasifier can significantly improve the availability of an IGCC plant.

Coal for Gasifiers

Oxygen-blown gasifiers typically operate better with bituminous and lower volatile coal. In most gasification systems, sulfur content of the coal is only a design consideration for the sulfur-removal system and not an operating limitation on the gasifier.

The composition of coal and some of its physical properties have important influences on the gasification  process. Young coals such as lignite and sub-bituminous coal generally contain a high percentage of moisture and oxygen, while old coal, such as bituminous coals and anthracite, tend to become sticky as they are heated. As a result, in the entrained flow gasifier the coal must be dried, because if the water enters the gasifier, some of it   will react with CO to form hydrogen and CO2. Moisture content has no effect on the gasification process in the fixed bed gasifier because the hot gas leaving the gasifier dries the coal as it enters the gasifier.

Since oxygen is present in the gasification process, coals containing more oxygen will need less oxygen or air to be added. For example, an E-gas gasifier system requires 2,220 tons per day of oxygen for sub-bituminous coal, 2,330 tons per day of oxygen for bituminous coal, and 2,540 tons per day for pet coke. The oxygen in coals is particularly important in air-blown gasification as any oxygen in the coal will reduce the amount of air required for the gasification reaction and thereby reduce the resulting nitrogen in the syngas.

Mercury Control with Gasification

Mercury control from coal gasification is applied to the syngas before it is burned, resulting in a significant volumetric reduction from handling flue gas.

For entrained flow systems, essentially all of the mercury in the coal will be present in the syngas. Since syngas volume is considerably less than flue gas, mercury removal systems greater than 90% can be relatively easily applied to the syngas stream.

Integrated Gasification Fuel Cell Systems

Fuel cells make it possible to generate electric power with high-efficiency, environmentally benign conversion of fuel to electric energy. If the fuel cells are fueled on syngas from coal, the United States can achieve energy security by using an indigenous fuel source and producing clean-high-efficiency power. Many countries globally, including the United Kingdom, Italy, Germany and Japan, are promoting the development of high-temperature fuel cells for distributed generation and central power.

Fuel cells are electrochemical devices that convert chemical energy in fuels into electrical energy directly.  This technology generates electric power with high thermal efficiency and low environmental impact. Unlike conventional power generation technologies (e.g., boilers and heat engines), fuel cells do not produce heat and mechanical work and are not constrained by thermodynamic limitations. Since there is no combustion in fuel cells, power is produced with minimal pollutants. Operation of fuel cells on syngas from gasified coal is the ultimate goal of the U.S. Department of Energy’s Solid State Energy Conversion Alliance (SECA) program.

This program extends coal-based solid oxide fuel cell technology for central power stations to produce affordable, efficient, environmentally friendly electricity from coal.

In general fuel cells are capable of processing a variety of fuels. The Department of Energy in August 2005 selected the first two projects under the Department’s new Fuel Cell Coal-Based Systems program. The projects will be conducted by General Electric Hybrid Power Generations Systems and Siemens Westinghouse Power Corporation. Each team will develop the fuel cell technology required for central power stations to produce affordable, efficient, environmentally friendly electricity from coal. This coal-based solid oxide fuel cell technology will be applied to large central power generation stations.

The Fuel Cell Coal-Based Systems program is expected to become a key enabling technology for FutureGen. The two teams will demonstrate fuel cell technologies that can support power generation systems larger than 100 MW capacity. Key system requirements to be achieved include:

• 50% plus overall efficiency;
• capturing 90% or more of the carbon dioxide emissions; and
• a cost of $400 per kilowatt, exclusive of the coal gasification unit and carbon dioxide separation subsystems.

Projects will be conducted in three phases. During Phase I, the teams will focus on the design, cost analysis, fabrication and testing of large-scale fuel cell stacks fueled by coal synthesis gas. The Phase I effort is to resolve technical barriers with respect to the manufacture and performance of larger-sized fuel cells. To conduct Phase I, each team is awarded $7.5 million. The duration of Phase I is 36 months.

Phases II and III will focus on the fabrication of aggregate fuel cell systems and will culminate in proof-of- concept systems to be field-tested for a minimum of 25,000 hours. These systems will be sited at existing or planned coal gasification units, potentially at the DOE’s FutureGen facility.

Solid Oxide Fuel Cell Coal-Based Power Systems

General Electric Hybrid Power Generation Systems will partner with GE Energy, GE Global Research, the Pacific Northwest National Laboratory and the University of South Carolina to develop an integrated gasification fuel cell system that merges GE’s SECA-based solid oxide fuel cell, gas turbine and coal gasification technologies. The system design incorporates a fuel cell/turbine hybrid as the main power generation unit.

Siemens Westinghouse Power Corporation is partnering with ConocoPhillips and Air Products and Chemicals Inc. to develop large-scale fuel cell systems based on their in-house gas turbine and SECA-modified tubular solid oxide fuel cell technology. ConocoPhillips will provide gasifier expertise, while the baseline design will incorporate an ion transport membrane (ITM) oxygen separation unit from Air Products.

CO2 Overview

Over the last three decades, utilities have implemented emission control equipment to control NOX, SO2 and particulate emissions on a large number of coal-fired boilers resulting in significantly improved air quality. Additionally, great progress is being made toward development of low-cost controls for mercury emissions. Public policy dictating reduction of greenhouse gas (GHG) emissions will pose the next major environmental challenge.

Oxyfuel

Of the 325,000 MW of coal-fired power capacity currently in the U.S. generation, which is just over half of the power generated annually, about 90% is provided by pulverized coal combustion. Technologies that can be retrofitted into some of the plants of the existing fleet will have the potential for greater impact on GHG reduction than those requiring construction of new plants. If public policies require GHG emission reductions, oxyfuel combustion is expected to be applicable to the existing pulverized coal plants as well as new pulverized coal plants. For new plants, optimization is anticipated to result in significant improvements in efficiency and reduction in cost.

Technical Description

In a conventional coal-fueled power plant, coal is combusted with air to produce heat and generate steam that is converted to electricity by a turbine-generator. As a result, the flue gas streams are diluted with large quantities of nitrogen from the combustion air. Air contains 78% nitrogen; only the oxygen in the air is used to convert the   fuel to heat energy.

In the oxyfuel power plant, combustion air is replaced with relatively pure oxygen. The oxygen is supplied by an on-site air separation unit, with nitrogen and argon being produced as byproducts of the oxygen production. In the oxyfuel plant, a portion of the flue gas is recycled back to the burners and the nitrogen that would normally  be conveyed with the air through conventional air-fuel firing is essentially replaced by carbon dioxide by recycling the carbon dioxide. This results in the creation of a flue gas that is a concentrated stream of carbon dioxide and other products of coal combustion, but no nitrogen. This concentrated stream of carbon dioxide is then compressed for transportation and storage in geologic formations.

Advanced processes are also being developed that would reduce the amount of flue gas recycled in an effort to reduce parasitic power. Optimization of the process is also under development, such as integration of the power required by the CO2 compression train and perhaps the air separation equipment. Process integration has the potential to increase efficiency and reduce cost.

Performance

Current designs suffer considerable degradation in heat rate (i.e., fuel consumption), due to the high power requirement of the cryogenic air separation unit and for compression of the concentrated CO2 stream to transport for storage. To satisfy these additional parasitic power requirements, the power plant heat rate is estimated to increase to about 12,000 Btu/kWh, resulting in a reduction in net plant efficiency to about 28%. However, potential reductions through development of membrane oxygen separation technologies and increased steam temperature boilers offer potential to decrease heat rate to perhaps 9,800 Btu/kWh HHV (35% net efficiency) or better, which would be about the same as the average coal-fired fleet efficiency in the U.S. today.

Cost

The production of a concentrated stream of CO2 is a key to enabling storage from fossil power plants. Many technologies are being investigated to facilitate the production of a concentrated CO2 stream from coal-fired power plants including advanced amine flue gas scrubbing, and oxyfuel combustion. The quality and quantity of economic analyses for these technologies is quite limited. All capture technologies are significantly more costly than conventional pulverized coal combustion and no clear economic winner has yet emerged. Of the options, amine scrubbing and oxygen combustion also provide the opportunity for retrofit onto the existing fleet as well as for new green-field or brown-field plants.

In an oxyfuel plant, the impact on the boiler island is minimal. In fact, as the quantity of flue gas recycled is reduced, the boiler island cost reduces as well. By far, the largest costs are in the air separation unit and CO2 cleaning and compression train.

Direction of Technology Development

Several engineering studies of both retrofit and new oxyfuel designs have been made and limited pilot scale testing has been completed. Many major equipment manufacturers have completed a significant amount of pilot testing. The next logical step is a small-scale demonstration under utility conditions. Such a demonstration would aid in identifying technology areas for further development and reveal the means of integration and opportunities for significant cost reduction.

Several studies are still needed. These include: plant optimization incorporating an ultra-supercritical boiler, reduction of the quantity of recycle gas, integration of the power requirements for the compression train and lower cost, lower power oxygen production methods.

Proposed Solution Pathways

Reducing or offsetting CO2 emissions from fossil fuel use is the primary purpose of the new suite of technologies called carbon dioxide capture and storage (CCS). Carbon dioxide can be captured directly from the industrial source, then concentrated into a nearly pure form and stored in geological formations far below the ground surface. Carbon dioxide capture and storage is a four-step process. After the CO2 is separated from the flue gas, it is compressed to about 100 bars, where it is in a liquid phase. Next, it is put into a pipeline and transported to the location where it is to be stored. Pipelines transporting CO2  for hundreds of kilometers exist today. The last step  is to inject it into the medium in which it will be stored.

CO2 can be injected into deep underground formations such as depleted oil and gas reservoirs, brine-filled formations or deep unmineable coal beds. This option is in practice today at three industrial scale projects and many smaller pilot tests. At appropriately selected storage sites, retention rates are expected to be very high, with CO2 remaining securely stored for geologic time periods that will be sufficient for managing emissions from combustion of fossil fuels. The potential storage capacity in geological formations is somewhat uncertain, but estimates of worldwide storage capacity in oil and gas fields range from 900 to 1,200 billion tonnes of CO2 and the estimated capacity in brine-filled formations is expected to be much greater. The U.S. is estimated to have a very large capacity to store CO2 in oil fields, gas fields and saline formations, sufficient for the foreseeable  future.

Three industrial-scale CCS projects are operating today. Two of them are associated with natural gas production. Natural gas containing greater than several percent CO2 must be “cleaned up” to pipeline and purchase  agreement specifications. The first of these projects, the Sleipner Saline Aquifer Storage Project, began nearly 10 years ago. Annually, 1 million tonnes of CO2 are separated from natural gas and stored in a deep sub-sea brine- filled sandstone formation. The In Salah Gas Project in Algeria began in 2004 and is storing 1 million tonnes of CO2 annually in the flanks of a depleting gas field. The third industrial-scale CCS project, located in Saskatchewan, Canada, uses CO2 from the Dakota Gasification Plant in North Dakota to simultaneously enhance oil production and store CO2 in the Weyburn Canadian Oil Field. Depending on the generation technology, 1,000 MW coal-fired power plants may emit from 6 million tonnes to 10 million tonnes/year of CO2. These are a greater volume than the existing capture and storage projects, but experience suggests that capture and storage of this magnitude should be possible.

Cost of CO2 Capture and Storage Is a Significant Barrier to Deployment

Estimated additional costs for generating electricity from a coal-fired power plant with CCS range from $20 to

$70/tonne of CO2 avoided, depending mainly on the capture technology and concentration of CO2 in the stream from which it is captured. While this metric may be useful for comparing the cost of CCS with other methods of reducing CO2 emissions, the increase in costs of electrical generation may be a more meaningful metric. Costs would increase from $0.02/kWh to $0.05/kWh, depending on the generation technology and baseline.

Capture and compression typically account for over 75% of the costs of CCS, with the remaining costs attributed to transportation and underground storage. Pipeline transportation costs are highly site-specific, depending strongly upon economy of scale and pipeline length.

In addition to the high cost of CCS, the loss of efficiency associated with capture and compression is high. The post-combustion, “end-of-pipe” capture technologies use up to 30% of the total energy produced, thus dramatically decreasing the overall efficiency of the power plant. Oxy-combustion has a similarly high energy penalty, although eventually, new materials may lower the energy penalty by allowing for higher temperature and consequently more efficient combustion. Pre-combustion technologies are estimated to require from 10 to 15% of energy output, leading to higher overall efficiency and lower capture costs.

Public and privately sponsored research and development programs are aggressively working to lower the costs of CO2 capture. The U.S. Department of Energy has a cost goal of $10/tonne CO2. This challenging target is  likely to be hard to meet without significant advances in separations technology, including membrane separators and new absorbents. Recent outreach efforts by the Department of Energy and the National Academy of Sciences are tying to engage academic researchers with new ideas in these areas.

At first glance, CO2 capture and storage in geological formations may appear to be a radical idea that would be difficult and perhaps risky to employ. Closer analysis, however, reveals that many of the component technologies are mature. A great deal of experience with gasification, CO2 capture and underground injection of gases and liquids provides the foundation for future CCS operations.

No doubt, challenges lie ahead for CCS. The high cost of capture, the large scale on which geological storage  may be employed, and adapting our energy infrastructure to accommodate CCS are significant hurdles to overcome. But none of these seem to be insurmountable, and progress continues through continued deployment  of industrial-scale projects, research and development, and growing public awareness of this promising option for lowering CO2 emissions.

The 10 largest coal producers and exporters in the Indonesia:

1. Bumi Resouces
2. Adaro Energy
3. Indo Tambangraya Megah
4. Berau Coal
5. Bukit Asam
6. Baramulti Sukses Sarana
7. Harum Energy
8. Mitrabara Adiperdana 
9. Samindo Resources
10. United Tractors

Source: The National Coal Council