By D. Gregory McGinnis, Duke Energy; Philip C. Rader, Alstom Power Inc.;
Raymond R. Gansley, Alstom Power Inc.; Wuyin Wang, Alstom Power Sweden AB
In response to the anticipated base electrical load growth and the need for clean energy solutions, Duke Energy is constructing a new nominal 800 MW unit as part of an overall modernization of their existing Cliffside, N.C. facility.
Work is underway on Duke Energy’s 800 MW Cliffside coal-fired expansion project in North Carolina. Courtesy Duke Energy.
The complete project involves retiring four 1940s-vintage units, adding a wet flue gas desulphurization (WFGD) system on Unit 5 and constructing a new super-critical coal-fired generating facility (Unit 6). Unit 6 is currently under construction and is expected to be in commercial service in 2012.
Like all new generating facilities, Cliffside Unit 6 is subject to strict emission limits for sulfur dioxide (SO2), sulfuric acid mist, mercury and total and filterable particulate. In addition, effective control of other acid gases, including HCl and HF, is an important consideration from both an environmental standpoint as well as impacts on equipment operation and maintenance. To achieve typical modern permit limits, new generating facilities burning high sulfur coal must be equipped with a dry electrostatic precipitator (ESP) or fabric filter (FF) for particulate control, WFGD system for sulfur dioxide and acid gas control and a wet electrostatic precipitator (WESP) for sulfuric acid mist control.
To evaluate the alternative air quality control system (AQCS) options for Cliffside, Duke established a cross-functional team and used a decision analysis process to select the “best balanced choice.” The evaluation team consisted of representatives of Fossil Hydro operations, strategy and construction and project management. Using evaluation criteria and ratings determined by the team, Duke determined that the Alstom Integrated AQCS technology was the best balanced choice for the Cliffside project. The team performed separate sensitivity studies that confirmed the choice of Alstom’s proposed technology. A separate net present value evaluation confirmed the choice of Alstom’s AQCS.
Alstom’s integrated air quality control system combines dry (DFGD) and wet (WFGD) flue gas desulfurization systems. In the integrated process, sulfuric acid mist, hydrogen chloride, mercury and particulate are removed by the DFGD stage, with SO2 and additional mercury and HCl removal occurring in the downstream WFGD. The WFGD purge stream is sent to the DFGD, where it is spray dried and collected in the fabric filter, thus avoiding the need for wastewater treatment and discharge.Eight Process Steps
The principal process steps are as follows:
1. The flue gas is cooled in the spray dryer absorber (SDA) using a lean, lime slurry. Since the SDA outlet temperature is well below the acid dew point, the SO3 in the flue gas condenses as sulfuric acid (H2SO4) mist. The sulfuric acid mist reacts with the lime slurry and is captured in the fabric filter as calcium sulfate. Experience with DFGD systems and recent pilot testing has shown that sulfuric acid mist emissions are expected to be less than 1 ppm (around 0.004 lb/MBtu).
2. Significant mercury capture also occurs in the DFGD. Depending on the fuel and boiler/SCR design, more than 85 percent to 90 percent mercury capture is expected in the DFGD stage.
3. Significant HCl and HF capture occurs in SDA. The HCl and HF react with lime to form dry solids (for example, calcium chloride and fluoride), which are removed in the fabric filter.
4. Sulfur dioxide (SO2) capture in the DFGD stage is minimized by temperature control and sub-stoichiometric reagent feed to minimize lime usage. The small amount of SO2 that is captured reacts to form a mixture of calcium sulfite and sulfate, which is removed as a dry solid in the fabric filter.
5. SO2 removal is accomplished in a conventional manner in the WFGD stage with low-cost limestone. Wallboard quality or landfill gypsum is produced. Alstom’s open spray tower technology is capable of achieving greater than 99 percent SO2 removal.
6. Additional HCl, HF and oxidized mercury removal occurs in the spray tower as well.
7. The purge stream required to control chlorides and inert fines for wallboard gypsum production is returned as a component of the lime slurry feed to the DFGD stage where it is spray dried in the SDA. Dissolved and suspended solids in the purge stream are captured in the fabric filter and removed as dry solids with the ash.
8. No wastewater treatment system is required to treat the purge stream from the WFGD dewatering system. In addition to the capital cost savings, the operating costs associated with this equipment (that is, energy costs, treatment chemicals, maintenance and so on) are avoided.
Integrated AQCS Features/Benefits
Like other specifications for new high-sulfur coal-fired units, the Cliffside specifications initially called for an alloy WESP as the means of controlling sulfuric acid emissions. In the IAQCS process, total particulate and sulfuric acid mist concentrations are reduced to the required permit levels through the use of DFGD technology consisting of a rotary atomizer spray dry absorber and fabric filter. Benefits include:
- Lower material costs by employing carbon steel SDA in place of an alloy WESP
- Lower construction costs due to simple SDA design (compared to WESP) and reduction in amount of alloy field welding
- Reduced exposure to alloy price volatility
- Improved O&M cost predictability with DFGD vs. WESP.
As a substantial quantity of the incoming HCl is removed by the DFGD stage, chloride levels in the WFGD absorber can be controlled to low levels (less than 12,000 ppm). This allows the use of lower-grade stainless steel, resulting in capital cost and operating cost savings. The Cliffside project’s original fuel specification had fuel sulfur levels up to 5.0 lbs SO2/MMBtu and up to 1,300 ppm chloride in the fuel.
During further project development, it was decided to include fuel chloride levels up to 3,000 ppm to allow added flexibility of fuel sourcing. The integrated AQCS design was able to address the higher chloride condition by increasing the lime addition to the DFGD area for more HCl removal and increasing the WFGD purge rate sent to the DFGD area for evaporation.
Because additional HCl could be removed in the DFGD area, the WFGD absorber operating chloride design level was maintained at 12,000 ppm, even at the highest fuel chloride condition. Thus, the material choice for the absorber remained alloy 2205 instead of a more expensive alloy needed for higher operating chloride designs.
Waste Water Treatment System
A purge stream is required to control chloride and inert fines contamination in WFGD gypsum. NPDES limits on dissolved/suspended solids, heavy metals and other constituents typically require that the purge stream be treated in multi-stage processing facilities to reduce suspended solids, heavy metals and organic compounds. By evaporating the purge stream in the SDA, Alstom’s IAQCS process eliminates the capital and operating costs associated with purge stream treatment. An added benefit is that the plant owner does not have to permit, monitor and report on the purge stream discharge.
For Cliffside, a wastewater treatment system (along with the ongoing operating and maintenance costs) is not required for the Unit 6 AQCS. Because the Unit 5 WFGD system needs to operate independently of Unit 6, a wastewater treatment system (WWTS) is planned. However, when Unit 6 is operating, most or all of Unit 5 purge can be accommodated in the Unit 6 SDA, thus reducing or eliminating O&M costs associated with the Unit 5 WWTS.
Traditional WFGD systems remove nearly all HCl in the flue gas into the absorber slurry and generate a wastewater purge stream to maintain the dissolved chloride level within the design limit for the selected materials of construction and control gypsum quality. Eliminating the need for a wastewater purge stream reduces make-up water consumption for the integrated AQCS design. This is significant make-up water savings/wastewater elimination, particularly as the fuel chloride level increases.
Additional water conservation measures are being included to allow use of cooling tower blowdown (CTB) or a blend of CTB with river water as make-up water to both the Unit 5 and Unit 6 AQCS systems.
Mercury Capture Capability
Based on the fuel chloride levels and the presence of an SCR, a high degree of mercury oxidation is expected at Cliffside. Based on testing, high levels of oxidation are conducive to mercury capture in both wet and dry FGD systems.1 Since the integrated AQCS design includes DFGD and WFGD systems in series, the majority of the mercury is expected to be removed in the DFGD area, which includes a fabric filter. The WFGD absorber is expected to act more as a polishing stage for oxidized mercury not captured by the DFGD.
Since only a small portion of the total mercury removed is projected in the WFGD, the potential for mercury re-emission from the WFGD is thought to be low relative to a design where the WFGD removes most of the mercury. The mercury content in the gypsum is also expected to be lower than in a conventional WFGD-only system.
Since a lean feed of lime slurry is used in the DFGD area to remove sulfuric acid and a portion of the HCl, the effect on the ash composition is small compared to a conventional DFGD application. There is also a small contribution of solids, mainly gypsum solids from the WFGD purge stream that is added to the ash. For the Cliffside performance basis fuel (17.96 wt.% ash, 3.55 lbs SO2/MMBtu and 531 ppm Cl in fuel) the total addition of solids to the fly ash collected is expected to be less than 5 percent. The effect on ash composition increases for high flue gas sulfuric acid and HCl levels and for lower fuel fly ash content. Analysis of representative ash samples from a pilot plant study has been completed and no troublesome issues for cement use were identified.
The Unit 6 AQCS design considers a wide range of fuels including eastern bituminous and western sub-bituminous coals. Design includes fuel blends with sulfur levels up to 5.0 lbs SO2 per MMBtu, and chloride levels up to 3,000 ppm on a weight basis.
The flue gas leaves the two air heater outlets (by others) and is combined into a common duct that rises vertically to the inlet of two 50 percent spray dryer absorbers (SDA). Separate gas paths are maintained through the fabric filters. Gas leaves the fabric filter to the two axial flow ID fans. The gas is combined in a common duct and enters the single open spray tower (OST) absorber. A new two-flue stack will serve both Units 5 and 6.
The WFGD portion of the Unit 6 AQCS shares common equipment with the new WFGD system for Cliffside Unit 5. The limestone preparation system has two horizontal ball mills (one operating and one redundant), each rated at 48 tph. Redundant reagent slurry storage tanks, pumps and feed loops to both absorbers are included. Hydrocyclones are used for the primary dewatering step with the underflow collected in filter feed tanks (two provided). Two horizontal belt filters are provided to produce wallboard-quality gypsum.
Two 68-foot-diameter SDAs contact the flue gas with the lime reagent and partially quench the flue gas while evaporating the purge flow from the WFGD system. The capacity of the SDAs to evaporate water not only allows for all of the purge from Unit 6 to be evaporated, but also allows for the complete WFGD purge stream from Unit 5 to be evaporated in the SDAs under most scenarios when Unit 6 is operating. The SDA is a standard Alstom design using three top-entry gas inlets per vessel, each equipped with a rotary atomizer.
The lime preparation system includes three detention type slakers, each sized for 50 percent of the maximum demand condition. Since the plant had a wide range in lime demand due largely to the range in fuel chloride level (up to 3,000 ppm Cl in fuel) the choice of 50 percent slakers allows for the operation of one slaker only under lower chloride operating scenarios and avoids turndown issues on the slaker for these conditions.
Slaked lime slurry is combined with the purge from the WFGD absorbers in a pre-mix tank. The pre-mix tank overflows to an SDA feed tank, which provides suction to an SDA feed pump that delivers the slurry to the atomizers. Any additional make-up water needed to quench the flue gas is added to these tanks. A redundant set of tanks, feed pump and feed line to the SDAs is included for reliability.
The fabric filter is Alstom’s LKP intermediate pressure, pulse jet design. Two casings are provided, each with 12 compartments with a 3.6-ft/min net-1 air-to-cloth ratio. The bags are 26.5 feet long of a blended PPS/P84 material with an intrinsic coating.
The spray tower absorber is designed for 99 percent SO2 removal over the range of fuel sulfur levels. The absorber is Alloy 2205 construction designed for continuous operation with dissolved chloride levels of up to 12,000 ppm. The design includes five normally operating spray levels for the maximum sulfur condition, with each spray level fed by a single slurry pump. The absorber is designed for up to 13 feet per second saturated flue gas velocity. The reaction tank diameter is expanded relative to the absorption section to allow for adequate gypsum residence time. Absorber design features include dual orifice spray nozzles on the bottom four spray levels with a high degree of spray overlap and Alstom’s wall ring technology. An organic acid additive system is included (shared with Unit 5 absorber); its intended use is to maintain SO2 removal in the event of an unplanned spray pump outage.
The principal quantitative benefit of the Integrated Air Quality Control System is a savings in lifecycle costs. The capital and operating costs were compared by combining the sum of the present day capital cost and the discounted value of future operating costs over the period of concern. The net present value (NPV) method is commonly used in the engineering project business to compare the economic merits and viability of alternative scenarios in which expenditures are made and the economic impact is felt over a period of time. In this method, the annual O&M costs were calculated based on the plant/unit capacity factor and AQCS system operating performance (for example, power consumption, reagent consumption and so on). The long-term impact of each O&M cost component was evaluated using the net present value method.
Pilot testing of the DFGD stage was performed on a roughly 1 MW equivalent slipstream at Cliffside Unit 5. The pilot plant consisted of a dual-fluid nozzle spray drying and fabric filter, along with related auxiliary equipment (for example ducts, fans, lime slurry and scrubber purge feed systems, and so on). Purge liquor was collected from the existing WFGD system at Duke Energy’s Marshall Steam Station and transported to Cliffside for testing. Provisions were made to spike the Unit 5 slipstream with SO2, SO3 and HCl to simulate the range of Unit 6 operating conditions.
Pilot plant testing at Cliffside confirmed:
- Low SO3 emissions (<<1 ppm)
- Selective removal of HCl in the presence of SO2
- Lime stoichiometric ratio requirements
- Effective drying of WFGD purge stream.
Ash/byproduct samples were collected and submitted for analysis and testing for use in cement. Initial testing indicated that the byproduct was within the required specifications for cement manufacture.
The Integrated AQCS combines Alstom’s dry and wet flue gas desulfurization systems in an innovative way that will reliably achieve stringent emission requirements at a lifecycle cost well below that of competing technologies. Major cost savings are achieved by replacing a wet electrostatic precipitator with a spray dryer absorber and eliminating the need for wastewater treatment equipment for the WFGD system. Other advantages include reduced water consumption and the ability to employ low-cost materials for construction for the WFGD absorber.
Authors: D. Gregory McGinnis is with Duke Energy, based in Charlotte, N.C. Philip C. Rader and Raymond R. Gansley are with Alstom Power Inc. based in Knoxville, Tenn. And Wuyin Wang is with Alstom Power Sweden AB.
Reference: 1 J. E. Locke, Withum, J. A., Tseng, S. C., CONSOL Energy, “Mercury Emission from Coal-Fired Facilities with SCR-FGD Systems,” Proceedings of Air Quality V Conference, Sept. 2005.
See Cliffside 6 firsthand! Tour the Cliffside 6 project site as part of Coal-Gen, August 18-21 in Charlotte, N.C. For details on the technical tour, visit www.coal-gen.com.