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NITROGEN OXIDES (NOx) EMISSIONS FROM COAL

NOx refers to both nitric oxide (NO) and nitrogen dioxide (NO2). The environmental effects of releasing too much NOx into the atmosphere are listed below.

  • NOx is a main constituent in the formation of ground-level ozone which causes severe respiratory problems.
  • Respiratory problems may result from exposure to NO2 by itself, but also of concern is NOx reacting to form airborne nitrate particles or acid aerosols which have similar effects.
  • Along with SOx, NOx contributes to the formation of acid rain and causes a wide range of environmental concerns.
  • NOx can deteriorate water quality by overloading the water with nutrients causing an overabundance of algae.
  • Atmospheric nitrogen-containing particles decrease visibility.
  • NOx can react to form nitrous oxide (N2O), which is a greenhouse gas, and contribute to global warming.

Coal usually contains between 0.5 and 3 percent nitrogen on a dry weight basis. The nitrogen found in coal typically takes the form of aromatic structures such as pyridines and pyrroles. The feedstock flexibility of gasification allows for a wide variation in the nitrogen content of coal.

During gasification, most of the nitrogen in the coal is converted into harmless nitrogen gas (N2) which makes up a large portion of the atmosphere. Small levels of ammonia (NH3) and hydrogen cyanide (HCN) are produced, however, and must be removed during the syngas cooling process. Since both NH3 and HCN are water soluble, this is a straightforward process.

In coal gasification-based processes, NOx can be formed downstream by the combustion of syngas with air in electricity-producing gas turbines. However, known methods for controlling NOx formation keep these levels to a minimum and result in NOx emissions substantially below those associated with other coal-fired electrical production technologies, as seen in the following figure.

NOx Emissions of Currently Feasible Coal to Electricity Technology Options Without CO2 Capture

NOx Emissions Control
Although NOx emissions from operating IGCC power plants are quite low as shown above, stricter regulations may require control to levels as low as 3 ppm in the HRSG stack gas. Following is a review of both combustion-based and post-combustion NOx control methods used for NOx emissions control.

Turbine NOx Control
Available combustion-based NOx control options for syngas-fired turbines are more limited than those available for natural gas-fired turbines. The so-called Lean-Premix Technology1, which permits the latter to achieve emissions as low as 9 ppm (at 15% O2), is not applicable to IGCC gas turbines. Differences between syngas and natural gas composition and combustion characteristics are the source of the problem. Gasification-derived syngas differs from natural gas in terms of calorific value, gas composition, flammability characteristics, and contaminants. An oxygen-blown, entrained-flow IGCC plant will typically produce syngas with a heating value ranging from 250 to 400 Btu/ft3 (HHV basis), which is considerably lower than the 1000 Btu/ft3 for natural gas. This yields a significant flow rate increase compared with natural gas (~14% more), resulting from the need to maintain a specified heat input to the combustor. Furthermore, whereas the combustible composition of natural gas is primarily methane (CH4), the syngas combustible components are carbon monoxide (CO) and hydrogen (H2), with an H2/CO ratio generally ranging from 0.6 to 0.82. When compared to natural gas, the H2 component of syngas exhibits a higher flame speed and broader flammability limits. The latter means that the syngas should have a stable flame at leaner conditions than natural gas, while the former indicates that the kinetics (chemical reaction speed) of H2 combustion are much quicker than that of natural gas. This very fast flame speed of the hydrogen component of the syngas prevents the use of the lean-premix technology. Finally, coal gasification-derived syngas will likely contain higher concentrations of H2S than natural gas, which may impact post-combustion NOx control technologies.

The use of a diluent to lower flame temperature, such as nitrogen or steam, is currently the preferred method for minimizing NOx generation from a syngas-fired turbine. Nitrogen is usually available from the cryogenic air separation unit, so it can conveniently be employed in the IGCC process. This control method can reduce NOx emissions levels from syngas-fired turbines to approximately 15 ppm (at 15% O2). GE is currently targeting development of combustors to reliably achieve below 10 ppm NOx with syngas, which would be comparable to the NOx emission levels achieved through use of the lean-premix technology on gas turbines firing natural gas.

Post-Combustion NOx Control
The only methods currently available to achieve single-digit NOx concentrations require treatment of the flue gas to reduce the NOx to nitrogen. Selective catalytic reduction (SCR) is a fully commercial technology that has been applied to natural gas-fired turbines to minimize NOx, while the EMx (SCONOx™) process is a newer, non-ammonia based technology which competes with SCR.

Selective Catalytic Reduction (SCR)
SCR technology is generally considered as a best available add-on NOx control for stationary combustion turbines that fire natural gas or fuel oil, and is also a candidate for use in IGCC. SCR selectively reduces NOx emissions by injecting ammonia (NH3) into the exhaust gas upstream of a catalyst. The NOx reacts with NH3 and O2 to form N2 and H2O, primarily according to the following equations:

4NH3 + 4NO + O2 → 4N2 + 6H2O
4NH3 + 2NO2 + O2 → 3N2 + 6H2O

The catalyst’s active surface is usually a noble metal, base metal (titanium or vanadium) oxide, or a zeolite-based material. Metal-based catalysts are typically applied as a coating over a metal or ceramic substrate, while zeolite catalysts are typically a homogeneous material that forms both the active surface and the substrate. The geometric configuration of the catalyst body is designed for maximum surface area and minimum obstruction of the flue gas flow path to maximize conversion efficiency and minimize back-pressure on the turbine. The most common configuration is a monolith, "honeycomb" design. An important factor that affects the performance of SCR is the operating temperature. Base-metal catalysts have an operating temperature window for clean fuel applications of approximately 400° to 800° F. The upper range of this temperature window can be increased using a zeolite catalyst to a maximum of 1,100°F. Due to the required operating temperature range for conventional SCR catalyst (600-750°F), integration into the HRSG normally requires splitting of the HP evaporator (or boiler) section to accommodate the SCR catalyst bed and ammonia injection equipment.

An ammonia injection grid, designed to disperse the ammonia uniformly throughout the exhaust flow, is located upstream of the catalyst body. In a typical ammonia injection system, anhydrous ammonia is drawn from a storage tank and evaporated using a steam- or electric-heated vaporizer. The vapor is mixed with a pressurized carrier gas to provide both sufficient momentum through the injection nozzles and effective mixing of the ammonia with the flue gases. The carrier gas is usually compressed air or steam, and the ammonia concentration in the carrier gas is about 5 percent. An alternative to using anhydrous ammonia is to use aqueous ammonia. The reduced ammonia concentration in an aqueous solution reduces safety concerns associated with anhydrous ammonia.

The ammonia-to-NOx (NH3:NOx) ratio can be varied to achieve the desired level of NOx reduction. It takes one mole of ammonia to reduce one mole of NO, and two moles of ammonia to reduce one mole of NO2. Higher NH3:NOx ratios achieve higher NOx emission reductions, but can result in increased unreacted ammonia being emitted into the atmosphere. This unreacted ammonia is known as ammonia slip. SCR catalysts degrade over time, which changes the quantity of NH3 slip. Catalyst life will typically range from 3 to 10 years depending on the specific application. IGCC applications, with exhaust gas that is relatively free of contaminants, should yield a significantly longer catalyst lifetime than for a conventional coal-fired application.

Installation of SCR in an IGCC’s HRSG, for what amounts to NOx polishing, requires consideration of the environmental impacts of ammonia slip. Ammonia slip is typically limited to less than 5 ppm in most SCR applications, but may be higher when the NOx level entering the catalyst bed is so very low. Such operation may require more excess ammonia than is typically used. While the tradeoffs between NOx and ammonia are not simple, from a qualitative perspective they are both acutely toxic; both contribute to the formation of fine particles of ammonium sulfate ((NH4)2SO4) and ammonium nitrate (NH4NO3), acid deposition, eutrophication, and nitrogen enrichment of terrestrial soils; and both may ultimately be converted to nitrous oxide (N2O), a powerful greenhouse gas. In addition, NOx (as NO2) is a chronic toxin and an essential precursor to the formation of tropospheric ozone. The contribution of NOx or ammonia emissions from a single facility to any of these environmental problems is primarily determined by existing levels of NOx and ammonia in the area and the concentration of other pollutants in the atmosphere that react with the NOx or NH3. In terms of the range of influence or potential for long-range transport, nitric acid or organic nitrate (peroxyacetylnitrate, PAN) derived from NOx emissions, and ammonia have similar lifetimes in the atmosphere and, thus, similar potential for long-range transport. PAN and ammonium sulfate, however, are longer-lived and can spread the influence of both NOx and ammonia over a wide area.

Disposal of salt deposits and spent catalyst are also potential environmental issues. SCR catalysts typically contain heavy metal oxides such as vanadium and/or titanium, thus creating a potential human health and environmental risk related to the handling and disposal of spent catalyst. Vanadium pentoxide, the most commonly used SCR catalyst, is on the EPA list of Extremely Hazardous Materials. The quantity of waste associated with SCR is quite large, although the actual amount of active material in the catalyst bed is relatively small. This requires the use of licensed transport and disposal facilities and compliance with RCRA. It is conceivable that facilities in some states may face added costs by having to dispose of these materials out of state due to a lack of licensed disposal facilities that will handle these materials. This responsibility may not be borne by the plant since catalyst suppliers often collect and recycle spent catalyst as part of their contract.

An additional environmental issue related to SCR is that of occupational safety. Permit applicants need to be aware of ammonia safety concerns as an issue, which in itself may mitigate the benefit of using SCR to control NOx. The EPA characterizes ammonia as an extremely hazardous substance, and vapors may form an explosive mixture with air. OSHA regulations require that employees of facilities where ammonia is used be trained in safe use of ammonia (under 29 CRF 1910.120). Facilities that handle over 10,000 pounds of anhydrous ammonia or more than 20,000 pounds of ammonia in an aqueous solution of 20 percent ammonia or greater must prepare a Risk Management Plan (RMP) and implement a Risk Management Program to prevent accidental releases. The costs for training, meeting appropriate Federal, State and local safety codes, and the preparation and approval of the RMP and Emergency Preparedness Plan must be taken into consideration when assessing the technology. All this said, ammonia is a broadly used in a variety of applications, especially agriculture, and with appropriate preparation can be handled and used safely.

There are two major operational impacts resulting from the installation of an SCR system in the HRSG of an IGCC plant. First, the pressure loss across the SCR catalyst bed increases the turbine back-pressure, thereby decreasing gas turbine output by approximately one-half percent. The ammonia storage and transfer equipment consumes some additional power. Second, unwanted chemical reactions may negatively impact and interfere with the operation of the plant. Although IGCC fuel gas cleanup equipment efficiently removes more than 95% of the sulfur constituent (as H2S), the residual sulfur in the syngas passes to the combustion turbine where it is oxidized to both SO2 and SO3. Ammonia slip from the SCR process can react with the SO3 forming ammonia salts such as ammonium sulfate or ammonia bisulfate. Ammonium bisulfate is a very corrosive and sticky material that can plug downstream heat transfer equipment, reducing performance or even causing plant shutdown. The additional back-pressure caused by the fouling will also reduce the gas turbine output. The ammonium sulfate, if not deposited with any bisulfate formed, is discharged to the atmosphere as fine particulate matter (PM2.5), since no particulate control is typically installed downstream of the HRSG. This problematic behavior represents another important difference between a natural gas-fired plant and the IGCC power plant.

In order to prevent ammonia salt formation, either the ammonia slip or the SO3 must be greatly minimized. Since some ammonia slip is inevitable, IGCC suppliers recommend that a maximum sulfur oxide level of 2 ppm be allowed to enter the HRSG with the fuel gas. Installation of a zinc oxide or activated carbon polishing reactor, upstream of the gas turbine, is one method to control the residual SO2 (with the added benefit of some added mercury control). Unfortunately, this further increases parasitic power consumption and significantly raises the cost of the SCR installation.

EMx (SCONOx™) Oxidation/Absorption Cycle
This post-combustion catalytic system removes both NOx and CO from the gas turbine exhaust through the use of a platinum catalyst. Unlike SCR, it does not require the use of ammonia injection, and the active NOx removal reagent is potassium carbonate. The exhaust gases from a gas turbine flow into the reactor and react with potassium carbonate that is impregnated onto the platinum catalyst surface. The CO is oxidized to CO2 by the platinum catalyst. NO is oxidized to NO2 and then reacts with the potassium carbonate coating on the catalyst to form potassium nitrites and nitrates at the surface of the catalyst. These chemical reactions, shown below, are referred to as the "Oxidation/Absorption Cycle."

CO + ½O2 → CO2
NO + ½O2 → NO2
CH2O + O2 → CO2 + H2O
2NO2 + K2CO3 → CO2 + KNO2 + KNO3

When the carbonate becomes saturated with NOx, it must be regenerated. The effective operating temperature range is 280-750°F, with 500-700°F being the optimum range for NOx removal. The optimum temperature range is approximately the same as that of SCR. The regeneration of the catalyst is accomplished by passing a dilute hydrogen reducing gas across the surface of the catalyst in the absence of oxygen. The hydrogen reacts with nitrites and nitrates to form water and elemental nitrogen. CO2 in the regeneration gas reacts with potassium nitrites and nitrates to reform potassium carbonate. This cycle is referred to as the "regeneration cycle," as shown below.

KNO2 + KNO3 + 4H2 + CO2 → K2CO3 + 4H2O + N2

Water vapor and elemental nitrogen are exhausted up the stack instead of NOx, and potassium carbonate is once again present on the surface of the catalyst, allowing the oxidation/absorption cycle to begin again.

Because the regeneration cycle must take place in an oxygen-free environment, the catalyst undergoing regeneration must be isolated from exhaust gases. This is accomplished using a set of louvers, one upstream of the section being regenerated and one downstream. During the regeneration cycle, these louvers close and a valve opens allowing regeneration gas into the section. A typical SCONOx™ system has five to fifteen sections of catalyst. At any given time eighty percent of these sections are in the oxidation/absorption cycle, and twenty percent are in the regeneration cycle. Because the same numbers of sections are always in the regeneration cycle, the production of regeneration gas proceeds at a constant rate. A regeneration cycle typically is set to last for three to five minutes, so each section is in the oxidation/absorption cycle for nine to fifteen minutes.

Several critical issues associated with the use of this technology are:

  • Catalyst is very sensitive to sulfur, including trace quantities that are typically found in IGCC exhaust gas;
  • Reliability of moving parts over time is an operational and maintenance concern;
  • Use of hydrogen for regeneration could be a serious safety concern, since it is hard to contain;
  • Scale-up issues for large gas turbines;
  • SCONOx™ has about twice the pressure drop of SCR; and
  • The initial capital cost is about three times the cost of SCR, although this may come down once there are more systems in operation.

In 1997, the EPA monitored the application of SCONOx™ on a natural gas-fired turbine at the Federal Cogeneration facility in Los Angeles, where it established a 3.5 ppm (at 15% oxygen on a 3-hour rolling average) standard for NOx. The SCONOx™ control system has typically achieved average NOx emissions of approximately 2 ppmv. This resulted in being designated as having achieved a LAER (lowest achievable emission rate) at 3.5 ppmv, which set the standard for future control technology for similar facilities per Section 173(a)(2) of the Clean Air Act.

The South Coast Air Quality Management District designated SCONOx™ as the Best Available Control Technology (BACT) for natural gas-fired turbine engines. A further improvement in reductions was certified in 1998, when the EPA found that SCONOx™ had achieved a LAER of 2.5 ppmv.

Post-combustion NOx reduction at IGCC Facilities in the United States
Information from permits/permit applications on recent IGCC projects includes NOx emissions rates as shown in the accompanying figure. Note that not all IGCC projects, among them the very recently executed Duke Edwardsport IGCC-based power plant and Mississippi Power’s Kemper County IGCC, have been required to implement post-combustion NOx control, though others such as HECA in California are planning on doing so with SCR, which correlates with decreased NOx emissions.

NOx emission rate comparison for IGCC projects
NOx emission rate comparison for IGCC projects
[Source: Environmental Performance of IGCC Power Plants, Steve Jenkins (CH2M HILL, Inc.) & George Booras (Electric Power Research Institute), 4th International Freiberg Conference on IGCC and XtL Technologies, May 3, 2010]

Finally, it is interesting to see the effects of implementation of SCR on NOx and other pollutant species in the context of an IGCC plant. The following chart shows the emissions of major regulated pollutants for Duke Energy’s Edwardsport IGCC plant, both without and with SCR in operation, in comparison with the limits specified in the Class V NSPS permit. Obviously, NOx is reduced significantly with SCR and other pollutants are subtly affected. However, in either case, emissions of all regulated pollutants are well below the permit-specified limits.


Edwardsport IGCC Plant Combustion Turbine Emissions, lb/hr
Syngas-firing, 100% load (59°F), SCR Off Syngas-firing, 100% load (59°F), SCR On Permitted Limit
NOx
169.0 57.0 633
CO 92.5 93.0 194
SO2
28.9 29.0 633
VOC 3.3 3.3 8.4
PM/PM10/PM2.5 36.0 39.1 80.1
H2SO4* 3.2 6.4 N/A

1. The lean-premix combustion process goes by a variety of names, including the Dry Low-NOx (DLN) process of General Electric, the Dry-Low Emissions (DLE) process of Rolls-Royce/Allison, and the SoLoNOx process of CATERPILLAR/Solar Turbines. Most of the commercially available systems are guaranteed to reduce NOx emissions to the 9 to 25 ppm range, depending on the manufacturer, the particular turbine model, and the application. A few manufacturers have guaranteed NOx emissions in the range of 9 ppm (e.g., GE). As the NOx emission level is lowered, some manufacturers have experienced problems with combustion vibration (dynamic pressure oscillations) and premature combustor deterioration. These technologies may result in an increase in CO and unburned hydrocarbons by as much as 50 ppm.
2. Todd, D. and Battista, R., “New Developments in LCV Syngas Combustion / IGCC Experience,” General Electric technical paper, 2001.


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