Low-rank, high-moisture coals constitute about 50% of U.S. and world coal reserves. Given the abundance of these low-cost coals, the use of high-moisture coal for power generation is already common and is growing. In the U.S. alone, plants burning high-moisture coals produce nearly a third of the coal-fired electric generation, according to the Department of Energy.
Unfortunately, plants that utilize high-moisture coal pay a substantial price in efficiency. When such coals are burned in utility boilers, about 7% of the fuel heat input is used to evaporate and superheat the moisture in the fuel. Most of this lost heat can be attributed to the energy needed to evaporate the moisture in the fuel. Furthermore, high-moisture, low-heating value coals result in higher fuel and flue gas flow rates, auxiliary power requirements, net unit heat rate, and increased mill, coal pipe, and burner maintenance compared to bituminous (hard) coals. Conversely, a reduction in coal moisture through thermal drying improves boiler and unit efficiency, plant operation, and economics while reducing CO2 and criteria emissions.
Coal Creek Station has improved performance through coal drying with the DryFining process at both units, in commercial operation since 2009.
COAL DRYING IMPROVES PERFORMANCE
The opportunities for thermal integration to dry coal are site-specific and depend on the available heat sources, space constraints, and general layout of the plant. The benefits of coal drying, such as heat rate improvement, increase as the moisture in the coal is reduced. The achievable reduction in coal moisture content may be limited by thermal performance of the boiler convection pass, the amount of available heat, or by the equilibrium moisture content of coal.
“A reduction in coal moisture through thermal drying improves boiler and unit efficiency, plant operation, and economics while reducing CO2 and criteria emissions.”
To take advantage of the benefits of using waste heat to dry coal at power plants, a novel low-temperature coal-drying and -cleaning process was developed. This process employs a moving bed fluidized bed dryer (FBD) that harnesses waste heat from the power plant to decrease the moisture content of low-rank coals. This technology, commercially available as the DryFining Fuel Enhancement Process (DryFiningTM), was developed and commercialized by Great River Energy (GRE) at its Coal Creek Station (2×600 MW).
For existing units, depending on site specifics, coal drying with DryFining has been demonstrated to reduce total coal moisture (TM) by 10 to 20 percentage points (see Table 1). The higher end of the range corresponds to supercritical power plants.
TABLE 1. Net unit heat rate improvement through drying of high-moisture coals
The maximum improvement in net unit heat rate (∆HRnet), shown in Table 1, represents off-site coal drying and the delivery of dry coal to the site. The minimum corresponds to basic DryFining thermal integration options. The results are conservative because the analysis did not account for system draft and fan power reductions. A new plant with integrated DryFining will have a lower capital cost, compared to a plant burning raw coal, including the front-end coal drying system, and will not be limited by the boiler convection pass performance.
Implementation of onsite thermal drying in newly built power plants operating with high steam parameters (i.e., supercritical and ultra-supercritical steam cycles) is especially beneficial for units burning low-rank coals that contain higher moisture content (see Figure 1). This is because the efficiency of such plants is more negatively affected by the high coal moisture content. A reduction of coal moisture is necessary to achieve the very high efficiencies made possible through supercritical, ultra-supercritical, and eventually advanced ultra-supercritical technologies.
THE DRYFINING FUEL ENHANCEMENT PROCESS
GRE’s moving bed FBD is the heart of the DryFining system, which serves two important functions. It cleans the coal by removing a significant portion (~30%) of the sulfur and mercury from the raw coal in the first FBD stage and then dries the coal in the second stage. The cleaning function, accomplished by gravitational segregation in a fluidized bed, distinguishes this technology from others commercially available and provides the critical co-benefit of emissions reduction. At those power plants that do not have modern environmental controls applied, a process that removes pollutants from coal and increases power plant efficiency could have even greater value than a process that only dries the coal.
A moving bed FBD was selected for the DryFining process because such a process offers rapid heat and mass transfer, resulting in a more compact dryer design. The coal is fluidized by air instead of the commonly used steam.B Potential devolatization of coal during the drying process is avoided by drying with low-grade waste heat from the power plant.
Crushed coal is fed to the first stage of the fluidized bed dryer, where non-fluidizable material such as rocks and other higher-density fractions are segregated at the bottom of the dryer, while less dense and smaller particles float. Therefore, the segregated stream discharged from the dryer has higher mineral matter content (including pyrite) in comparison to the dried coal (product stream). As most of the inorganically associated sulfur is contained in pyrite forms, in the case of North Dakota (ND) lignite, about 30% of the sulfur and mercury (Hg) from coal are segregated out in the first stage of the FBD.4,5,8
FIGURE 1. Effect of coal rank and steam parameters on net unit efficiency
The tests conducted with other lignites and sub-bituminous coals confirm that about 20 to 30% of sulfur and mercury in the coal can be segregated out. The amount of segregated sulfur and mercury depends on many factors, such as the percentage of inorganically associated sulfur in the coal, the presence or absence of clays, and other factors related to coal morphology.
After segregation, the fluidizable material next enters the dryer’s second stage, where the surface and a portion of the inherent coal moisture are evaporated by the heat supplied by the fluidizing air and the in-bed heat exchanger. The in-bed heat exchanger increases the temperature of the fluidizing (drying) air and fluidized coal bed, improving drying kinetics (the rate of coal drying). The drying process affects the microstructure of coal particles that disintegrate during drying. The drier and finer coal is discharged from the FBD as the product stream. The bed residence time and temperature primarily control the residual moisture content.
FIVE YEARS OF OPERATING EXPERIENCE
Three series of controlled tests were conducted on Coal Creek Unit 1 at full gross load (i.e., 600 MW), steady-state operating conditions before and after the implementation of coal cleaning and drying with the DryFining process. The coal cleaning and drying equipment was sized to treat up to 1100 tons/hr of raw North Dakota lignite with moisture content in the range of 38% to 40%. The process has been in continuous commercial operation at Coal Creek Station since December 2009.
Measurements were made at the power plant with the raw (wet) coal and no treatment in September 2009 to establish baseline unit performance and emissions. Then tests with the DryFining process in service were performed in March–April 2010 and October 2011. Those test results are summarized in Table 2. The complete test report is available elsewhere.4
TABLE 2. Coal Creek Unit 1 operating conditions with and without coal drying applied
Operating Conditions
When the coal was dried, air preheater (APH) air leakage decreased due to the lower drafts. In addition, the temperature of flue gas at the APH exit decreased, resulting in lower volumetric flow of flue gas entering the flue gas desulfurization (FGD) system. As Coal Creek employs a FGD gas bypass to avoid condensation at the power plant stack, less flue gas means that less can be bypassed, which allows a larger proportion of the flue gas to be scrubbed and reduces overall plant emissions even further.
As a consequence of the reduced FGD bypass flow, the stack temperature decreased, but remained well above saturation temperature. Also, with lower flue gas temperature, flue gas velocity through the electrostatic precipitator decreased, resulting in improved particulate collection efficiency and lower opacity.
Unit Performance and Emissions
The effect of drying the coal with the DryFining process was measured through changes in the net unit heat rate and boiler efficiency, fuel and stack flow, and mill and induced draft (ID) fan power (see Table 3). During the October 2011 tests, the coal moisture content was reduced by five percentage points (i.e., 13%), resulting in a 10.6% increase in coal heating value. Further reduction of fuel moisture at Coal Creek was limited by steam temperatures, which began to decrease due to the lower flow rate of flue gas through the convective pass of the boiler. There are plans to increase the boiler heat transfer surface area to allow further coal drying in the future.
The decrease in coal utilization rate resulted from the increased higher heating value (HHV) of the coal. The reduced-moisture coal also had improved grindability, thus mill power decreased by almost 10%. This allowed the unit to be operated with six mills in service, instead of the customary seven or eight. Freeing one of the mills to be used as a spare improved plant availability, as mills can be rotated in and out of service for routine maintenance or repair without reducing the fuel- processing capacity. In addition, mill maintenance is no longer carried out during plant outages when labor is more costly.
The volumetric flow rate of flue gas downstream of the APH decreased with the lower coal flow rate and flue gas temperature, resulting in lower draft losses and lower ID fan horsepower.
With drier coal, the net unit heat rate (HRnet) decreased by 3.5%, while boiler efficiency increased by 3.4%. The improvement in net unit heat rate is higher than the improvement in boiler efficiency because, with drier coal, the station auxiliary power requirement is reduced compared to the raw, wet coal.
The reduction in CO2 emissions determined by using the performance test data shown in Table 3 was 3.5%. However, this reduction was somewhat limited by site-specific conditions; other power plants could potentially achieve greater efficiency improvements. At Coal Creek, adding additional heat transfer surface area to the boiler will allow further reductions in the coal moisture content, with a projected heat rate improvement of 4.5% and a more than 4.6% reduction of CO2 emissions. The CO2 intensity was reduced by 3.0%.
The implementation of coal drying with the DryFining process also had a significant positive effect on NOx, SO2, total mercury (HgT), and CO2 emissions (see Table 4). A reduction in NOx emis- sions is attributed to the lower coal input and lower ratio of primary air (PA) to secondary air (SA), compared to operation with raw coal.
TABLE 3. The effect of DryFining on the performance of Coal Creek Unit 1
TABLE 4. Effect of DryFining on emissions at Coal Creek Unit 1
Parametric testing before separated over-fired air installation in the late 1990s revealed hot primary air drying to the mills to be the top NOx driver. The resulting 30% NOx reduction allowed Coal Creek to meet its new NOx emission limits by boiler tuning, avoiding a costly installation of a selective non-catalytic or catalytic reduction (SNSR or SCR) reactors.
SO2 emissions reductions were attributable to three factors. First, the lower flow rate of dry coal to the boiler reduced the amount of sulfur entering the boiler. Second, a significant portion of the inorganically bound sulfur (approximately 30%) was segregated out by the moving FBD. Finally, the lower volumetric flow of flue gas allowed a larger proportion of flue gas to be scrubbed (with less being bypassed), further reducing SO2 emissions (see Figure 2).
FIGURE 2. SO2 removal in the FGD before and after implementation of DryFining
The 35–40% reduction in HgT emissions is due to reduced coal combustion (as a result of higher efficiency), removal of approximately 30% of the pyrite-bound mercury from the coal during coal cleaning, change in mercury speciation, and increased flow rate of flue gas through the FGD where oxidized mercury (Hg2+) is removed. The reduction in HgT emissions allowed Coal Creek to meet new emissions limits with FGD additives to reduce Hg2+ re-emission, thereby avoiding activated carbon injection.
Overall, by implementing DryFining at Coal Creek, Great River Energy avoided an estimated $366 million in capital expenditures, which would otherwise be needed to comply with emissions regulations.
LONG-TERM OPERATING EXPERIENCE
DryFining has been in continuous commercial operation at Coal Creek Station for over five years, achieving availability higher than 95% without causing a single unit outage.
The performance, in terms of reducing the heat rate, of both Coal Creek units has continued to improve since commercial operation of the DryFining process began in December 2009. Figure 3 offers a comparison of monthly average net unit heat rate values. The average annual improvement in net unit heat rate for Unit 1 is 3.4%—virtually the same as measured during the baseline tests. The heat rate improvement for Unit 2 of 5.8% is higher because it also includes the effect of a steam turbine upgrade. The station net generation has increased since implementing DryFining since the auxiliary power use of each unit has decreased 5 MW.
FIGURE 3. Monthly average net unit heat rate for refined (2013) and raw (2009) coals
Annual averages of NO and SO emissions for Units 1 and 2 at Coal Creek are presented in Figure 4 for the 2005–2013 time period. Following implementation of DryFining, SOx emissions were reduced by 44–46%, while the NOx emissions were reduced by 24–25%, compared to the 2005–2009 average. The long-term reduction in NOx was smaller compared to the test results presented in Table 4, because changes in unit load and combustion settings, experienced in regular operation, increase NOx.
FIGURE 4. NOx and SO2 emission levels at Coal Creek Units 1 and 2 before and after implementation of DryFining
CONCLUSIONS
With a tremendous amount of low-rank, high-moisture coal reserves globally available and being increasingly utilized, it is important to integrate thermal drying to increase the efficiency of power plants relying on such fuels. A novel low- temperature coal drying and cleaning process, DryFining, employing a moving bed fluidized bed dryer and using waste heat to decrease moisture content of the North Dakota lignite and other high-moisture coals was developed in the U.S. by a team led by Great River Energy.
Considerable efficiency improvements and emissions reductions have been demonstrated with near-continuous operation since 2009. This process has allowed the plant to meet strict emissions standards without the addition of new equipment, saving an estimated $366 million in capital expenditures for emissions control equipment.
The potential application of coal cleaning and drying with DryFining can be expanded. It may also be very effectively used to improve the quality of washed coals,8 as well as to improve the efficiency of the plants that have switched from bituminous fuel to PRB to reduce SO2 emissions. Additionally, DryFining may be employed to improve the efficiency of coal gasification plants (e.g., IGCC and CTL) and lignite-fired oxy- fuel power plants using dry-feed gasifier designs.
NOTES
A. Oxy-fuel and oxygen-blown gasification plants are not subject to the equilibrium moisture content limit. The studies conducted with DryFining integrated with the lignite-fired oxy-fuel and CTL plants employing dry-feed gasifiers have demonstrated coal moisture reduction in the 40–55% range to the target moisture level of 8–12%.
B. Inert fluids, other than steam, may be used for fluidization to achieve deep reductions in coal moisture content.
Source: Nenad Sarunac - University of North Carolina at Charlotte, Mark Ness - Great River Energy, Charles W. Bullinger - Great River Energy
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