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Reducing
Nitrogen Oxide Emissions:
|
Category | Number of Boilers |
Standard (pounds of NOx/million Btu) |
Date for Compliance |
---|---|---|---|
Group 1 | |||
Phase I | 115 Dry Bottom Wall-Fireda | 0.50 | 1/1/1996 |
124 Tangentially Firedb | 0.45 | 1/1/1996 | |
Phase II | 308 Dry Bottom Wall-Fired | 0.46 | 1/1/2000 |
299 Tangentially Fired | 0.40 | 1/1/2000 | |
Group 2 | 145 Other Types | 0.68B0.86c | 1/1/2000 |
NSPS Units | All units with capacities greater than 73 megawatts that began operation or were modified between 8/17/71 & 9/18/78 | 0.8 for lignite from North Dakota, South Dakota, or Montana; 0.7 for solid fossil fuel; 0.6 for other lignite; 0.3 for oil; 0.2 for gas | 8/17/1971 |
All units with capacities greater than 73 megawatts that began operation or were modified after 9/18/78 | 0.8 for lignite from North Dakota, South Dakota, or Montana; 0.6 for other lignite, bituminous, and anthracite and 65 percent NOx removal; 0.5 for subbituminous and 65 percent for NOx removal; 0.3 for oil; 0.2 for gas | 9/18/1978 | |
Proposed Revisions for NSPS | All new or reconstructed units constructed after 7/9/97 with capacities greater than 25 megawatts | 1.35 lbs/mWh | 7/9/97 |
aDry
bottom refers to the form of the ash leaving the boiler. In dry
bottom boilers, the temperature remains below the ash melting point,
and the ash remains in a solid, "dry" form. Wall-fired refers to
the placement and orientation of burners in the combustion chamber.
Burners in wall-fired boilers are perpendicular to the wall of the
chamber, either all on one wall (front) or split between two facing
walls (opposed).
b Tangentially fired boilers are spaced around the chamber and angled to produce a rotating flame within the chamber. c Group 2 boilers consist of 36 Cell Burners with a limit of 0.68 lbs/mmBtu, 55 Cyclone Burners with a limit of 0.86 lbs/mmBtu, 26 Wet Bottom Wall-Fired Burners with a limit of 0.84 lbs/mmBtu and 28 Vertically Fired boilers with a limit of 0.80 lbs/mmBtu. lbs = pounds. MmBtu = million Btu. MWh = megawatthour. NSPS = New Source Performance Standards. Source: Energy Information Administration from Code of Federal Regulations and the U.S. Environmental Protection Agency. |
Federal Standards for Existing Units
Title IV, "Acid Deposition Control,"of the CAAA90 required the EPA to establish NOx emissions standards for older generating units. These standards go into effect in two phases. The first phase began in 1996. The affected units consisted of units named in Table A of Title IV, "Affected Sources and Units," or their substitution units that have tangentially fired(3) or dry bottom wall-fired(4) boilers. The second phase will begin in 2000.
A utility can choose to comply with the EPA Title IV NOx standards in one of four ways:
There were 239 coal-fired units required to meet the provisions of the first phase of the CAAA90 Title IV emissions limitations for NOx. Phase I applied to units that were affected by the Phase I requirements for SO2 under Title IV and had tangentially fired or dry bottom wall-fired boilers. The EPA has estimated the cost of the Phase I NOx reduction program to the electric power industry would be $267 million per year.(6)
All 239 units required to meet the Phase I limits on NOx emissions in 1996C144 Table A units and 95 substitution unitsC underwent verification of emissions rates, and all of them met their reduction requirements. There were 115 dry bottom wall-fired boilers and 124 tangentially fired boilers affected in the first year of the program (Table 2).
For utility units required to meet the Phase I Title IV NOx emissions limitations, both emissions rates and total emissions in 1996 were below 1990 levels. Their 1996 emission rates were cut by 40 percent, from the 1990 average of 0.65 pounds of NOx per million Btu of heat input to an average of 0.39 pounds of NOx per million Btu.(7) Compliance at the 239 units resulted in emissions levels approximately 314,000 tons (33 percent) below 1990 levels.(8)
Table 2. Boilers Subject to Title IV Phase I NOx Reductions in 1996Boiler Type |
Standard NOx Emissions Limit (lbs/mm Btu) |
Number of 1996 Table A Units |
Number of Substitution Units |
---|---|---|---|
Tangentially Fired | 0.45 |
82 |
42 |
Dry Bottom Wall-Fired | 0.50 |
62 |
53 |
A 38-percent reduction of approximately 290,000 tons of NOx was achieved by the 144 Table A units affected in 1996. For the 95 substitution units, emissions were reduced by 51,000 tons or 17.5 percent. Many of the substitution units were already lower emitters of NOx than the Table A units; for example, some had already been meeting a New Source Performance Standard only moderately higher than the 1996 Phase I limits. In fact, in 1990, some of the substitution units were already below the applicable NOx emissions rates required by Title IV in 1996.(9)
Although average emissions rates for the 239 Phase I units were 40 percent lower in 1996 than in 1990, the amount of NOx actually released into the air was only about 33 percent lower.(10) The difference resulted from higher fuel use by Table A units and substitution units. Without further reductions in emissions rates, NOx emissions from these units can be expected to rise with increased utilization.
The 1996 Emissions Scorecard released by EPA's Acid Rain Division(11) indicates that for 141 of the 239 Phase I units, low-NOx burner technologies were used for compliance in 1996 (Figure 1). At 67 of those units, low-NOx burners were coupled with a two-stage combustion process called "overfire air." At three other units, overfire air technologies alone were used for compliance. Overfire air technology diverts about 20 percent of combustion air at the burner level to air ports above the burner zone, reducing the oxygen availability at the burners.(12)
Retrofitting existing generating units with low-NOx burners was most frequently chosen for compliance because it is an economical way to limit the formation of NOx. NOx is produced through oxidation of nitrogen gas (N2) in the air and nitrogen chemically bound in the coal. The amount of NOx formed when coal burns is a function of the nitrogen content of the coal, the flame temperature, the amount and distribution of air during combustion, and the flame structure.
Low-NOx burners control fuel and air mixing to create larger and more branched flames, reduce peak flame temperatures and lower the amount of NOx formed. The improved flame structure also improves burner efficiency by reducing the amount of oxygen available in the hottest part of the flame. In principle, there are three stages in a conventional low-NOx burner: combustion, reduction, and burnout. In the initial stage, combustion occurs in a fuel-rich, oxygen-deficient zone where the NOx is formed. A reducing atmosphere follows, where hydrocarbons are formed and react with the already formed NOx. In the third stage, internal air staging completes the combustion. Additional NOx formation occurs in the third stage, but it can be minimized by an air-lean environment. Low-NOx burners can also be combined with overfire air technologies to reduce NOx further.(13)
Wall-Fired BoilersThree general categories of low-NOx burners for wall-fired boilers are (1) delayed combustion low-NOx burners, (2) external staged low-NOx burners, and, (3) internal staged low-NOx burners.(14) In delayed combustion burners, the fuel is burned slowly with long, low-intensity flames. The slow combustion and long flames result in lower flame temperatures, inhibiting thermal NOx formation. The slow combustion retards early fuel and air mixing, inhibiting the oxidation of nitrogen chemically bound in the fuel.(15) External staged burners function similarly to conventional burners but are equipped with tertiary air ports for staging conditions.(16) Internal staged low-NOx burners also retain conventional flame shapes but stage the combustion of the fuel and air within the burner itself. Internal staged low-NOx burner technologies are more efficient at reducing NOx while maintaining lower levels of unburned carbon.
Burner PerformanceTo assess the success of low-NOx burner technologies in reducing NOx emissions, data for wall-fired boilers before and after retrofitting with low-NOx burners were obtained from open literature and several utilities. The baseline emissions rates for the boilers represented in the data range from 0.57 to 1.34 pounds of NOx per million Btu before the retrofits, with a mean of 0.99 pounds per million Btu. After the retrofits, the controlled emissions rates range from 0.27 to 0.60 pounds of NOx per million Btu with a mean of 0.47 pounds of NOx per million Btu.
System ImpactsRetrofitting low-NOx burners in wall-fired boilers (Figures 2a and b) involves removing the existing burners and providing more space for the installation of the low-NOx burners. Normally, small modifications to the waterwall(17) and major modifications to the windbox are required for improved air distribution. Low-NOx burners are generally larger than conventional burners, and extensive bending of waterwall tubes usually is required to provide the additional space. For small furnaces, installation of low-NOx burners may cause flames to impinge on the opposite wall of the furnace. Derating of the unit load may be required to prevent flame impingement, which causes very high heat flux in furnace tubes, from occurring. Flames contain chemicals in highly active forms, such as free radicals, that can corrode the tube metal at high temperatures.
Extensive restructuring of the boiler configuration was required when retrofits were applied at Arizona Public Service Company's Four Corners Unit 4. Originally, Four Corners Unit 4 had 9 coal pulverizers serving 18 three-nozzle cell burners. The retrofit with low-NOx burners required the following modifications:
Operation of low-NOx burners in wall-fired boilers tends to increase unburned carbon in the ash. Unburned carbon can occur in both the bottom ash and the fly ash. Unburned carbon in the fly ash is termed "loss on ignition." Loss on ignition increased from 15 percent to 19 percent of the total fly ash weight when low-NOx burners were installed at the New England Power Company's Salem Harbor Unit 1. At Salem Harbor Unit 3, the loss on ignition level increased from 8 percent to 16 percent.
Increases in carbon monoxide and unburned carbon levels are attributed to imbalances in the distribution of air and fuel.(18) These problems can be alleviated by operating the low-NOx burners with systems that accurately regulate the fuel and air supplies.(19) Carbon monoxide and unburned carbon levels are very site-specific and depend on factors such as load, coal characteristics, furnace configuration and operating conditions.(20)
Other system impacts may include slagging in the lower furnace region. Because low-NOx burners are operated with fuel-rich conditions, a reducing environment is created, and coal slagging is increased. Modifications to the windbox(21) may be required to achieve optimal air flow and distribution for efficient combustion. Windbox modifications may result in major structural changes to the boiler unit.(22)
Low-NOx burners are effective at reducing thermal NOx formation because they reduce the high-temperature flame regions that are characteristic of conventional burners. High temperatures in the flame zone promote slagging on the furnace walls. Therefore, the operation of low-NOx burners can help reduce the rate of furnace slagging. This was evident during the operation of the low-NOx burners at Four Corners Unit 4, where the furnace exit gas temperatures decreased, upper furnace heat absorption increased by 31 to 66 percent, and boiler efficiency increased by approximately 1 percent.(23)
During the retrofit of the low-NOx cell burner technology at Dayton Power and Light's Stuart Station Unit 4, a few burners were modified to prevent high levels of carbon monoxide and hydrogen sulfide formation. Corrosion rates increased on the furnace walls, and chromatized coating was applied to the walls to prevent such damages. No significant modifications were made during the retrofit of West Penn Power's Hatfield's Ferry Unit 2. Overall, no major modifications to the boiler configuration were required for the retrofit of the low-NOx cell burner.(24) The cost of retrofitting a unit with low-NOx burners varies (Table 3).
Systems with Overfire AirSome wall-fired boilers combine the low-NOx burner technology with an overfire air technology that creates two stages for combustion. The two-stage combustion requires a primary and a secondary source of combustion air. The secondary air nozzles are located above the burners. This system results in more complete burnout of the fuel and formation of N2 rather than NOx.
Table 3 shows cost data for retrofits at Public Service of New Hampshire's Schiller Station Units 4, 5, and 6. Estimated cost data indicate that the total capital costs associated with the installation of low-NOx burner and overfire air systems depend on the following modification requirements:
Replacement or modification of existing burners
Tangentially Fired Boilers
Low-NOx burner technology for tangentially fired boilers differs from that for wall-fired boilers because of differences in firing configurations between the two boiler types (Figure 2c). The most commonly applied low-NOx burner technology in U.S. coal-fired boilers, the low-NOx concentric firing system, is specifically designed for tangentially fired boilers. Three systems are available, Levels I, II, and III.
Unlike the technologies for wall-fired units, overfire air plays a more integrated role in the low-NOx burner technologies applied to tangentially fired units. Level I is the only low-NOx concentric firing system that does not use separated overfire air. Level II incorporates separated overfire air and Level III uses both separated and close-coupled overfire air. In all three designs, protection against waterwall corrosion is achieved by diverting the combustion air toward the wall of the furnace. The close-coupled overfire air in the low-NOx concentric firing system Level III is integrated into the existing windbox by exchanging the highest coal nozzle with the air nozzle immediately below it. Thus, the top row supplies overfire air, and the next lowest row is for coal burners.
Burner Performance
Low-NOx concentric firing system retrofits require the replacement of all fuel and air nozzles; however, no major changes in the structure, windbox, or waterwall are needed. Retrofit applications of the low-NOx concentric firing system Level I have shown significant control of NOx emissions in tangentially fired boilers.
Performance data for the low-NOx concentric firing system Level I technology were collected from open literature and several utilities. To protect proprietary data, the names and unit-specific information on units obtained from utilities are not provided. For the units studied, the controlled levels ranged from 0.34 to 0.55 pounds per million Btu. The reductions in emissions after the retrofits ranged from 10 to 48 percent. The control efficiencies for low-NOx burners in tangentially fired units are lower than those reported for wall-fired boilers. Because the baseline emissions for tangentially fired units are lower than those in wall-fired units, the reductions to meet emissions standards are smaller.
Systems with Overfire Air
Low-NOx concentric firing system Level II is operated with separated overfire air. Both close-coupled overfire air and separated overfire air are integrated into the low-NOx concentric firing system Level III. With separated overfire air, more air at higher velocities can be introduced for better mixing. The Level III configuration allows for greater control and flexibility of air and fuel staging.
Several other low-NOx burner and overfire air technologies are available for tangentially fired boilers, but they have not been widely applied. For example, the clustered concentric tangential firing system is an advancement of the low-NOx concentric firing system, using burners that are grouped together. This design develops a more fuel-rich combustion environment than is produced in the low-NOx concentric firing system.
Cost estimates were obtained for the low-NOx burner and overfire air retrofits at two unnamed sites as well as for Public Service Company of Colorado=s Valmont Unit 5 and Cherokee Unit 4 (Table 3). The estimates for the unnamed plants were provided by vendors.
Table 3. Costs for Retrofitting Boilers with Low-NOx BurnersType of Boiler | Action or Site | Cost
(Dollars per Kilowatt) |
---|---|---|
Wall-Fired | Total Replacement | 14.5�.0 |
LNCBa (low range) | 5.5�0 | |
LNCB (high range) | 7.0�.0 | |
Four Corners Unit 4 | 21.9 | |
21 Selected Phase I Units | 9.3�.0 | |
Wall-Fired with Overfire Air | Schiller Station | |
Unit 4 | 6.81 | |
Unit 5 | 6.25 | |
Unit 6 | 7.62 | |
Tangentially Fired with Overfire Air | Valmont 5 | 15.0 |
Cherokee 4 | 11.5 | |
(Unnamed) Plant 1b | 42.42 | |
(Unnamed) Plant 2b | 6.34 | |
aLNCB
= Low NOx Cell Burner. bEstimates provided by vendors. Source: David South, Energy Resources International, 1997. |
Low-NOx burners are one of the technologies that can be used for controlling NOx emissions. New State and Federal standards for ozone will require additional reductions in NOx emissions. Currently, both the standards and the NOx control technologies are evolving. New NOx emissions limits may come from a requirement that was issued by the EPA on October 11, 1997, which requires State Implementation Plans to meet the current Federal 1-hour ozone standard of 120 parts per billion. The EPA intends to publish a supplemental notice of proposed rulemaking in early 1998 clarifying the requirement for ozone reduction. Part of the supplement will be a discussion of the interaction between the State Implementation Plan requirement and the CAAA90 Title IV requirements.(26)
The State Implementation Plan requirement was issued by the EPA in response to a petition from the Ozone Transport Assessment Group (OTAG).(27) (The OTAG petition called for the EPA to allow States to adopt a range of emissions levels to help meet ozone standards. OTAG also called for an intraregional emissions trading system. A final rulemaking is due in September 1998.
Additional NOx emissions limits for utilities may come from the NOx Budget Program of the Ozone Transportation Commission (OTC), or from Section 126 of of the Clean Air Act, which allows any State or political subdivision to petition the EPA for a finding that "any major source or group of stationary sources emits or would emit" any air pollutant in violation of Title I of the Clean Air Act. EPA will issue a notice of proposed rulemaking based on the petitions of a number of eastern States by September 30, 1998, and will take final action by April 30, 1999.
The OTC, which represents the State Environmental Directors of the Ozone Transport Region,(28) designed the NOx Budget Program with the goal of reducing region-wide emissions as part of the efforts by each State in the Ozone Transport Region to attain the national ambient air quality standards for ground-level ozone. These reductions are to occur in two phases, the first beginning in May 1999 and the second in May 2003.(29) From May through September 1999, the first period of the program, the region-wide seasonal NOx budget cap is 219,000 tons. The cap will remain in place until 2003, the start of the second phase of the program, when it will be reduced to 143,000 tons of NOx across the region. Each budget source will be allocated NOx allowances from the State in which it is located, on either an annual or multi-year basis.
Another new ozone standard was released by EPA in July 1997 in response to a court order to tighten air quality rules. Although it is more stringent, at 80 parts per billion rather than 120, the new standard is an 8-hour rather than a 1-hour standard. By 2000, States will be required to have designated areas for complying with the new standard. By 2003, implementation plans will be required.(30)
As operators have gained more experience with low-NOx burners, they havedeveloped more effective operating procedures to limit additional maintenance and costs. The cost and performance data for new technologies for controlling NOx to comply with the proposed new standards are also likely to evolve with experience.
Endnotes