By Douglas J. Smith IEng, Senior Editor
For the last four years Congress has discussed legislation for more stringent control of power plant emissions of sulfur dioxide (SO2), nitrogen oxide (NOx), carbon dioxide (CO2) and mercury (Hg). Effective January 1, 2000 the national cap for the emissions of SO2 was lowered to 8.95 million tons. Tougher NOx emissions reductions are also required under State and Federal laws by 2004.
In the near future it is expected that new national ambient air quality standards for ground level ozone and fine particulates may necessitate further reductions in NOx and SO2. Although not currently regulated, regulations for controlling emissions of mercury are expected by late 2004, with compliance by 2007.
Although some environmentalists may argue otherwise, the overall air quality is better in the U.S. than it was 30 years ago and the major reason has been the reduction of emissions from electric power plants. Over the last 25 years the U.S. electric utility industry has invested almost $40 billion in advanced technologies to reduce emissions from their plants. Between 1970 and 1998 the rate of emissions of SO2 dropped by 70 percent, NOx by 48 percent and particulate matter (PM-10) by 94 percent. Emissions of mercury from power plants that have installed emissions control technologies have been reduced by an average of 40 percent.
According to the Edison Electric Institute (EEI), a well designed, multi-emission approach can offer many environmental, energy and economic benefits. Such a strategy would streamline the regulatory process and accomplish the same air quality results at a much lower cost. EEI believes a well designed multi-emission approach that regulates NOx, SO2 and mercury would substantially reduce compliance costs.
Advanced Multi-pollutant Control
Babcock & Wilcox is looking at two possible configurations for controlling emissions of NOx, SO2, particulates and mercury from coal-fired power plants: One for plants burning high sulfur bituminous coal and the other for plants burning low sulfur coal from the Powder River Basin (PRB).
The high sulfur bituminous coal configurations would include:
- Low NOx burners
- Advanced high removal efficiency selective catalytic reduction (SCR)
- Fabric filter
- A limestone wet flue gas desulfurization (FGD) system with an integral wet electrostatic precipitator (WESP)
- An additive for mercury control
The PRB coal configuration would control emissions with:
- Low NOx burners
- Limestone injection into the furnace
- Particulate collection upstream of the SCR
- Advanced high removal efficiency selective catalytic reduction (SCR)
- Spray dry FGD system
- Fabric filter
The emissions goals for these advanced pulverized coal (PC) plants are shown in Table 1.
High levels of sulfur in bituminous coals present a challenge to minimizing the formation of sulfuric acid (H2SO4). A small portion of SO2 is oxidized to SO3 in the boiler. However, due to the presence of vanadium in the SCR’s catalyst, additional SO2 oxidation occurs across the SCR. When the SO3 combines with H2O vapor it forms sulfuric acid, which can cause corrosion of air heaters, fabric filter components, flues and the stack. As little as 5 ppm of sulfuric acid in the stack gas can produce a blue plume from the stack.
Although the formation of sulfuric acid can be prevented by increasing the air heater outlet temperature, this lowers the thermal efficiency of the boiler. However, if the amount of SO3 formed in the catalyst and the boiler is reduced it is possible to have a lower air heater outlet temperature. Reducing the amount of SO3 can be accomplished by injecting an alkali reagent upstream of the SCR. Final polishing of the H2SO4 takes place in the downstream wet ESP component of the wet FGD absorber tower.
Besides controlling NOx, the SCR may help control emissions of mercury in the wet FGD system. According to Greg Bielawski, manager environmental technologies, Babcock & Wilcox, SCRs have been shown to increase the relative amount of oxidized mercury and thus improve the ability to control mercury with the wet FGD. Measurements taken at several European boilers indicate that SCR catalysts oxidize elemental mercury.
There are two types of fabric filters used in electric power plants: reverse air and pulse-jet. Due to the pulse-jet’s smaller size and lower cost, it is generally preferred over the reverse air type of filter. In the proposed advanced emission control system, the pulse-jet is installed downstream of the SCR. The SO3 removal process, initiated with the reagent injection upstream of the SCR, continues in the pulse-jet fabric filter.
In the proposed plant configuration the integrated advanced absorber tower combines wet scrubbing and wet electrostatic precipitator (WESP) technologies for the simultaneous control of SO2, sulfuric acid mist, fine particulates and mercury. The wet ESP incorporated in the top of the wet scrubber serves to collect the sulfuric acid, residual fine flyash and any scrubber gypsum carryover. Thus, PM2.5 emissions are reduced.
It may be possible to design an advanced emission control system for plants burning high sulfur coals to achieve 99.5 percent SO2 removal, says Bielawski. Figure 1 compares the average SO2 emissions from a plant designed with advanced environmental controls versus wet scrubbers and the national average for coal-fired power plants.
According to Babcock & Wilcox, it may be possible for 90 percent of the mercury to be captured through the combination of particulate removal in the fabric filter, the oxidation of the mercury in the SCR and additives into the wet FGD system. Because the extremely low concentration of mercury contained in the gypsum is insoluble and thermally stable, it is not expected to adversely impact its use for wallboard or disposal in a landfill.
Low Sulfur PRB Coal Configuration
The major difference between the high sulfur configuration and the low sulfur configuration is the FGD system. With high sulfur coal a wet FGD system is used while PRB low sulfur coal uses a spray dry FGD system.
The low NOx burners used with high sulfur coals are also utilized on boilers burning low sulfur PRB coal. A typical SCR removal efficiency on a PRB unit is 60 percent with 2 ppm of ammonia slip. However, 95 percent removal efficiency is sought in the advanced plant. The NOx levels from the advanced plant configurations are the same relative levels as the NOx levels achieved at new gas turbine combine-cycle plant, says Bielawski.
For the PRB coal-fired advanced configuration, SO2 would be controlled by enhanced limestone injection dry scrubbing (E-LIDS), Figure 2. With nominal 0.8 percent sulfur/ 8,000 Btu/lb coal, 98 percent of the SO2 can be removed.
Because more of the mercury from low sulfur coal-fired units tend to be in the elemental form, it is more difficult to remove from the flue gas. However, as with the high sulfur coals, SCR catalyst may enhance the conversion of elemental mercury into oxidized mercury. Additives may also be used to promote the conversion of elemental mercury to the more easily removed oxidized mercury. As Babcock & Wilcox is still in the process of collecting data, it is not willing at this time to say how much mercury the system can remove.
A More Cost Effective Approach
In an interview at POWER-GEN International 2001, Kurt V. Steinbergs, executive vice president and chief financial officer, EnviroScrub Technologies Corporation, discussed his company’s “Pahlman Process” for controlling NOx and SOx emissions. According to Steinbergs, this new technology overcomes the cost and efficiency shortcomings of current emission control technologies.
The EnviroScrub technology can capture NOx and SOx selectively or simultaneously without the costs associated with conventional SCR and FGD scrubber systems. Although Steinberg would not discuss the technical details of the system because of proprietary concerns, he did say that their technology does not use expensive catalysts or ammonia gas and does not require any holding ponds for waste products. He further stated that their technology runs at a significantly lower pressure drop than competing SCR and FGD systems. There is also no problem with landfilling the gypsum by-product.
In addition to the gypsum, nitrates and sulfates are produced. However, these can be recovered during the regeneration of the proprietary “pahlmanite” material in the system. The nitrates and sulfates can be used by the fertilizer, chemical and explosive industries, says Steinbergs. The company reports that the technology has attained performance levels of 0.04 lb/MMBtu for NOx and 0.0003 lb/MMBtu for SOx on coal-fired plants and NOxlevels of 0.006 lb/MMBtu when installed on natural gas-fired units.
EnviroScrub has demonstrated their technology at two electric power plants: Ameren Energy’s Hutsonville high sulfur coal-fired power station in Illinois and Minnesota Power’s Boswell Energy Center. The Boswell Energy Center has four units burning low sulfur PRB coal.
At the Hutsonville plant 1,000 SCFM of flue gas was diverted from the stack to the demonstration unit. The flue gas contained an average 1,750 ppm of SO2 and 300 ppm of NOx. During the test, 99.8 percent of the SO2 and 75.3 percent of NOx was removed. Similarly, at the Boswell energy center the SO2 and NOx in the 1,000 SCFM of flue gas diverted were reduced by 99.98 percent and 91.6 percent, respectively.
According to Steinbergs, the company has plans to have a commercial unit available by the end of 2002. The commercial unit will be sized for units of 100-200 MW. However, because the ECO system is built in modules, a 1,000 MW unit could be easily constructed, says Steinbergs.
Multi-pollutant Pilot Plant
Powerspan Corporation of New Hampshire has pilot tested a multi-pollutant control system at FirstEnergy Corporation’s coal-fired R.E. Burger generating station, Figure 3. The patented process, called “Electro-Catalytic Oxidation (ECO)”, reduces emissions of NOx, SOx, fine particulate matter (PM2.5), mercury and hydrochloric acid.
With the ECO process the flue gas is treated in three steps to achieve multi-pollutant removal. In the first step, the majority of the ash in the flue gas stream is removed in a conventional dry ESP. Downstream of the ESP is a barrier discharge reactor which oxidizes the gaseous pollutants to higher oxides. In this section nitric oxides are reacted to form nitric acid, sulfur dioxide is converted to sulfuric acid and the mercury is oxidized to form mercuric oxides.
Products from the oxidation process, including fine particulate matter, are captured in a wet electrostatic precipitator (WESP). If needed the liquid effluent from the WESP can be treated to remove the ash and to produce concentrated sulfuric and nitric acids. The ECO system is designed for retrofitting into the last field of a plant’s existing ESP.
At the R.E. Burger plant, the ECO pilot system treated 2,000 to 4,000 SCFM of flue gas from Unit 5. The flue gas first entered the plant’s dry ESP where 90 percent of the fly ash was removed. After exiting the dry ESP the flue gas passed through a multi-tube, coaxial cylinder barrier discharge reactor where the gaseous pollutants were oxidized.
Following the reactor the flue gas entered the first of three WESP sections. The first section lowered the flue gas temperature, while the second section scrubbed any unconverted SO2 and captured any unoxidized NO2. Aerosols of nitric and sulfuric acids and fine particulate matter were removed as the flue gas traversed the second and third sections of the WESP. An induced draft fan at the outlet of the WESP returned the treated flue gas back to the plant. As the flue gas exited the pilot plant it was continuously monitored for CO2, NO, NOx and SO2.
Performance of the ECO pilot plant, Table 2, shows the system’s ability to remove NOx, SO2, mercury and fine particulate matter from the flue gas of a coal-fired unit. Based upon cost estimates developed for the R.E. Burger plant, Powerspan estimates that the capital cost for a an ECO system is $50/kW with a levelized cost of $1,471 per ton of NOx removed when operated on a seasonal basis-May 1 through September 30. According to Ellen Raines, spokesperson for FirstEnergy, they were very happy with the results of the pilot test program.
A joint venture between FirstEnergy and Powerspan is currently developing a 50 MW commercial demonstration ECO plant. The plant will be installed at FirstEnergy’s R.E. Burger plant and is scheduled to be operational by early 2003. The demonstration will last 30 months and if successful a full-scale commercial unit will be made available, says Stephanie Procopis, director of marketing, Powerspan.
Trading surplus allowances helps financing
Beginning in 2003 and 2004, the opportunity for power plants to finance the installation of NOx emission control equipment through the upfront sale of NOx allowances will expand. Currently, electric generation facilities 25 MW or greater in the eastern U.S. receive their NOx allowance allocations on a state-by-state basis. Some states are allocating credits a year at a time, while others are giving the utilities up to five year or longer.
According to Peter Zaborowsky, Evolution Markets, a more liquid over-the-counter market for NOx allowances has developed that allows sources to immediately sell forecasted surplus allowances and use the proceeds to pay for the installation of emissions controls. Using this method electric utilities can obtain “zero-cost” financing, says Zaborowsky.
As manager of independent power development at Long Island Lighting Company, Zaborowsky managed the installation of a major low NOx concentric firing system at one of the company’s power plants. This retrofit was financed entirely from the creation and sale of emission credits under New York’s State’s trading program.
According to Bob Pickering of Advanced Combustion Technology, Inc., Public Service of New Hampshire (PSNC) was one of the first in the nation to utilize NOx allowance markets to help offset the cost of installing NOx controls. In 1998, PSNC was able to sell in excess of $15 million of NOx allowances that helped them pay for the installation of an SCR, SNCR, low NOx burners and an over-fire air system.