By Don Labbe, Invensys Operations Management
The state of our electric utility industry is the subject of Lights Out, The Electricity Crisis, the Global Economy, and What It Means to You, by Jason Makansi. The book includes a lengthy discussion of the large-scale transition to western Powder River Basin coal (PRB) in the U.S., citing the issues of long shipping distances of PRB coal with its high water content. The book alludes to the inefficiencies of this transition but does not quantify the cost or burden. Since unit heat rate and CO2 production are influenced by coal type, this article investigates certain aspects of transitioning from PRB to bituminous coal.
Coal supplies have widely different sulfur and nitrogen content. In the drive to lower NOX and SOXemissions, coal utilization has shifted to predominantly low sulfur and nitrogen PRB coal. These coals have proven extremely effective in meeting state and federal emission requirements, but typically required furnace, fan and mill hardware modifications to maintain load generation rates. For utilities in the central and eastern U.S., these PRB coals have the disadvantages of higher water content, lower heating value and longer transportation routes than local bituminous coal. Coals that have minimal water content provide a carbon advantage; that is, lower CO2 production per unit of generation. Also, the fuel consumption associated with coal transportation results in significant CO2 generation of up to several percent of the power plant’s CO2 emissions.
Adding pollution abatement equipment proves effective in reducing NOX and SOX emissions. These systems typically have an operational margin that provide for some variability of coal supplies while attaining emission compliance. Significant reductions in CO2 can be achieved by using a coal mix with more bituminous coal, ultimately limited by the NOX and SOX emission limits.
Mixing coal sources to achieve lower CO2 challenges unit operations from coal handling to coal mills, furnace fuel and air controls, boiler steam temperature controls, soot blowing, precipitators, scrubbers and ash handling. To successfully manage blending coal supplies, unit controls must be flexible and adjust to the requirements of the mixed fuel. The allowable range of fuel variability may be limited by a single system, such as a selective catalytic reduction system (SCR) or flue gas desulfurization system (FGD).
Estimates of potential CO2 reductions achievable through the use of a mixture of local bituminous coal with PRB coal, while attaining NOX and SOX compliance, are presented. This article addresses the optimization considerations to provide satisfactory furnace, boiler and unit performance with blended coal supplies to make such operation feasible.
One salient point brought forward in Lights Out is the negative impact of long coal supply lines, in particular PRB coal with its high water content transported to eastern power plants. Since PRB coal is nearly one-third water, this adds substantial weight along with the diesel fuel consumption during transport which contributes to overall CO2 transportation-related emissions. Once on site, the fuel moisture content lowers the utility unit’s efficiency due to increased stack gas losses resulting in another CO2 penalty.
A roughly 0.2 percent heat rate penalty per 1 percent moisture results from the evaporation and heating of the water content entrained in the coal. This stems primarily from the high heat of vaporization of water1. One can liken the effect of entrained moisture in coal to the observed difference in the emitted heat from a campfire when burning wet wood as compared to dry wood. This underscores the value of maintaining dry coal supplies.
A sample calculation illustrates the potential reduction in CO2 that may result by transitioning from PRB to a more local bituminous coal for a typical coal-fired drum-type unit in the East. Several key assumptions are:
- The rail shipping distance of PRB coal is around 2,000 miles compared to around 500 miles for the local coal.
- The rail diesel fuel consumption rate is 500 miles per gallon per ton of coal. (CSX quoted value2 is 423 mpg/ton freight.)
- The moisture content of the PRB coal is 28 percent compared to 8 percent for the local bituminous coal
- The coal ultimate analyses of carbon content are 51 percent and 72 percent for PRB and bituminous coal, respectively.
This simple analysis illustrates the potential CO2 reduction by replacing PRB coal with local bituminous coal. This is not a rigorous derivation and is intended only as an example of the potential CO2 benefits.
A potential 8.5 percent reduction in CO2 emissions may be attained through a fuel switch. Reducing rail fuel consumption contributes nearly 2 percent of the total. The combination of the roughly 4 percent lower heat rate and the fuel’s carbon content provides a projected CO2 reduction for the unit of 6.67 percent. Of note, for the PRB coal case the ratio of transport fuel (lbs.) relative to coal consumption is 1.4 percent, so shortening coal supply lines can save a large quantity of diesel fuel.
The relative proportion of PRB that may be replaced by local bituminous coal depends on many factors including the performance capability of NOX/SOX emissions control systems and boiler/furnace operational flexibility.
The data presented in Figure 1 presents eight days of unit operation burning a blend of PRB coal and bituminous coal ranging from 25 percent to 75 percent PRB. A furnace optimization system operated continuously to achieve the lowest furnace NOX emissions consistent with the fuel blend. The data provides insight on the impact of blending coals on NOX emissions while dispatching the unit over a wide load range. The sensitivity of coal blend on coal mill power and induced draft (ID) fan demand are also illustrated. The PRB portion of total coal flow was estimated from the measured coal flow and the load applying the heating values for the PRB and bituminous coal.
Figure 1 PRB & Bituminous Coal Blend Effect on NOX, Mills and ID Fan
Retrofitting an SCR typically includes a design margin to ensure NOX emissions compliance with the design coal. Using furnace optimization, the NOX emissions exiting the furnace are typically lowered 15 percent to 25 percent. By lowering the furnace NOX, a downstream SCR has an increased operating margin to achieve NOX compliance.
The operating data above indicates that furnace optimization provides significant NOX reductions with coal blends. Combining SCR design margin with furnace optimization may allow coal blends to attain emissions objectives, thereby enhancing feasibility of blending.
Figure 2 illustrates this unit’s sensitivity of relative NOX emissions to the PRB blend for the range of unit loads. NOX emissions with PRB coal are approximately 40 percent lower than bituminous coal emissions levels. Experience with a wide range of bituminous coal indicates fairly consistent NOX emissions under furnace optimization. Therefore, the relative NOX reductions for a PRB coal blend should be consistent with a wide range of bituminous coals.
Figure 2 NOX vs. PRB % for Blended Coal Case
Figure 3 summarizes the mill power and ID fan demand at high loads for varying proportions of PRB coal. Since burning PRB coal requires more coal and air throughput than bituminous coal for the same generated load, the mill power requirement and ID fan demand are typically reduced as PRB coal fraction is lowered. This suggests coal mills and fans should not be limiting factors in transitioning from PRB to a PRB/bituminous mix.
Figure 3 Mill Power & ID Fan Demand vs. PRB % for Blended Coal Case
The next challenge in transitioning to a higher proportion of bituminous coal is achieving SOX emissions requirements. If the scrubber system has the capacity to handle higher sulfur coals, then attaining SOX emissions with a coal blend should be readily feasible. If the SOX scrubber system was designed for low sulfur PRB coal, then the proportion of bituminous coal may be limited at high loads. In either case, optimizing the SOX scrubber system may increase the proportion of higher sulfur bituminous coal.
Both wet and dry scrubbers have key control variables that can improve the SOX capture rate, providing an optimization opportunity for improved SOX reduction, for example slurry concentration and approach temperature for dry scrubbers. Bag house systems, while primarily designed for opacity control, also provide significant SOX capture capability when combined with dry scrubbers or chemical injection. Optimizing bag house control to increase the thickness of the ash cake and/or chemical injection may further enhance SOX capture rate and expand the allowable range of sulfur in the feed coal.
To further expand the CO2 reductions, the use of coal blends favoring bituminous coal at low and intermediate loads may be possible. Since the NOX SCR and SOX FGD systems are sized for full load these systems should have high operating margins at lower loads. However, adjusting coal blends quickly to meet load dispatch objectives may require increased flexibility in the coal source supplying each mill. One approach is to dedicate each mill to a specific type of coal. At low loads the mills supplying bituminous coal can supply the majority of the coal. As a NOX or SOX emission limit is approached with increasing generated load, the mills supplying PRB coal can assume a higher proportion of the total coal supply. The appropriate proportions can be adjusted through the optimization system.
Furnace Performance Optimization
PRB coal’s in-furnace combustion characteristics are substantially different from bituminous coal. These differences may shift furnace fouling rates and location of deposits, shorten flame ignition points and promote flame impingement on walls, alter superheat and reheat energy distribution, promote boiler tube failure rates and other adverse factors. The further need to lower furnace NOX emissions through furnace optimization places great importance on maintaining satisfactory furnace conditions over the spectrum of coal use.
One key to reducing furnace NOX emissions is controlling air/fuel ratios in the furnace’s combustion zone. The typical coal-fired furnace control applies air flow distribution through air dampers to influence these factors in addition to selecting coal mills and coal feed rates. The air/fuel ratios also have a significant influence on furnace fouling, flame ignition points and impingement, burner zone reducing environment and heat flux related to tube failures. There is also an impact on energy distribution and steam temperatures.
One method to optimize furnace operation is to apply sensors in the firing zone that measure key parameters and provide feedback to the optimization system. Combining visual furnace inspections during initial commissioning of these sensors defines the reasonable bounds or constraints for these sensory inputs. By incorporating these sensory inputs and their constraints into the optimization system, the furnace can achieve the desired objectives of NOX reduction coupled with maintaining satisfactory furnace conditions.
A challenge to the firing zone sensor approach is the hostile environment within the furnace that would adversely affect any physical sensor reliability. An alternative approach is to apply virtual burner zone sensors based on the primary measurements and controls of fuel and air distribution. Such virtual sensors have been applied with great success over many years in furnace optimization. The virtual sensors dynamically track load, coal feed changes and fuel quality changes, providing the feedback to modulate air dampers and coal feeder bias to maintain satisfactory furnace conditions while minimizing NOX formation3.
If a coal blend is used, then the burner zone virtual sensors would require information on the coal blend to each coal mill. If each mill supply silo has a specified coal type, then the operator can specify the coal through the DCS interface and thereby download the coal’s characteristics to the burner zone virtual sensors. If the coal supply silo is undergoing a change from one type of coal to another, the operator can specify the loading coal type. Applying residence time models in conjunction with mill measurements, the transition in coal type should be accurately determined by the coal property portion of the burner zone virtual sensors. If pre-blended coal of unknown proportion is fed to the mill silo, then mill measurements should provide sufficient information to approximate the coal blend with an estimated uncertainty. The coal blend characteristics and related uncertainty are applied to adjust the operating constraints of the burner zone virtual sensors in a conservative direction to maintain satisfactory furnace conditions at the expense of slightly higher NOX.
Burner zone virtual sensors provide a reliable method to monitor and control furnace conditions, avoiding harsh furnace conditions. Through the application of coal type assessment for each coal mill, these virtual sensors adapt to the coal blend and provide the necessary feedback to maintain satisfactory furnace operation over the range of load.
Boiler Performance Optimization
The distribution of energy within the furnace has a major impact on the efficiency of the boiler and the turbine. For maximum overall cycle efficiency, superheat and reheat steam temperatures should approach setpoint, while furnace exit gas temperatures should be as low as practical. Most boilers have limited means to adjust energy distribution:
- Burners in service
- Gas path dampers or burner tilts
- Stoichiometric firing and air flow
- Soot blowers.
In once-through units there is more flexibility in the energy distribution, since the heating process is continuous from sub-cooled water to superheater outlet. One control challenge is the balance between superheat and reheat steam temperatures. Excessive energy distribution to the reheat portion of the furnace may result in the need for reheat sprays and a possible cycle performance penalty. Too little energy to the reheat section results in cooler reheat temperatures and a drop in turbine cycle efficiency.
For drum type units, the distribution of energy is more complex due to fixed surface areas for evaporation, superheat, reheat and economizer functions. Maintaining the appropriate balance of energy distribution between the sections is typically a prime objective of a heat rate performance optimization system including soot blower optimization.
Figure 4 illustrates the steam temperature performance of an 850 MW coal-fired drum type unit prior to the installation of an optimization system4. The unit has tangentially fired drum type twin furnace boilers with eight coal mills supplying PRB coal. Design turbine throttle conditions are 1,000 F/1,000 F and 2,400 psig. The trend displays load, the A/B side superheat steam temperatures and A/B side reheat steam temperatures. The ranges of each trend are noted below the tags. The values in white correspond to the vertical time line or final time. A large A/B split in temperatures is apparent.
Figure 4 Superheat & Reheat Steam Temperatures Prior to Optimization
Figure 5 illustrates the steam temperature performance of the same unit after installing an optimization system. The system combines furnace optimization, soot blow optimization and model predictive steam temperature control to achieve greater side-to-side (A/B) balance for higher average steam temperatures, while lowering peak steam temperatures. The higher steam temperatures contributed to significant heat rate improvements illustrated in Figure 6. Lowering the peak steam temperatures reduced the high temperature stress and creep for the superheat and reheat sections resulting in a lower tube failure rate and higher unit availability. The furnace optimization also substantially lowered NOX emissions approximately 25 percent.
Figure 5 Superheat & Reheat Steam Temperatures Following Optimization
Figure 6 NOX & Heat Rate Benefits Following Optimization
The following benefits were documented from the system as determined on-line by the Delta Heat Rate Methodology4.
The mean values of the NOX and heat rate benefits are presented in Figure 7. The 0.67 percent heat rate improvement corresponds to a $700,000 fuel savings assuming $2.25/MMBtu and 60 percent capacity factor.
The furnace optimization system included burner zone virtual sensors to maintain satisfactory furnace conditions while lowering NOX emissions. These virtual sensors tracked load dispatching and mill starts and stops to provide continuous furnace monitoring and feedback to the optimization system.
The control of steam temperatures on this unit was particularly challenging due to an undersized superheater causing superheat temperatures to operate below set point during steady high load conditions. When operating below setpoint the superheat spray flow is shut off and steam temperatures are prone to rapid change during load ramps. Although little control action can be taken to curtail temperature drops, the model predictive steam temperature control proved extremely effective in limiting peak steam temperatures through precise regulation of superheat sprays and burner tilts. An additional benefit was a 25 percent increase in the unit ramp rate, since the prior steam temperature variations were limiting unit ramp rate.
Similar successes in NOX reduction, heat rate improvement, steam temperature control and ramp rate were achieved at the sister units5 through the application of optimization systems.
Since bituminous coal has a higher heating value than PRB and requires less air, the water wall section of drum type units burning bituminous coal has a higher heat flux. Burning bituminous coal in a unit designed for PRB shifts the balance of energy towards the evaporation portion of the boiler. This typically lowers superheat and reheat steam temperatures, unless there is significant margin in superheat and reheat tube surface area.
Soot blower optimization and stoichiometric firing through furnace optimization have proven effective in shifting energy distribution towards the needed area. If superheat and reheat temperatures are low, then shifting energy from the water wall section to the superheat and reheat passes would be an objective of these optimization systems.
If steam temperatures drop below setpoint during steady load operation, then the need for advanced control strategies becomes more pressing. Model predictive steam temperature control provides a means to precisely control peak steam temperature during dispatch operation. This approach provides tube protection for the superheat/reheat sections supporting rapid dispatch rates while maximizing unit heat rate.
The increasing application of renewable power sources places a further burden on fossil unit ramp rate. Utility units may be required to provide even faster dispatch response as more renewable power sources are plugged into the power supply chain. Since steam temperature control is the typical constraint on unit dispatch, upgrading to advanced strategies should contribute to additional ramp rate capability.
Enhancing ramp rate extends beyond steam temperature and boiler controls. Issues such as rate of change of pressure for thick-walled vessels and turbine life expenditure may need to be addressed. Advanced control strategies combined with furnace optimization may prove helpful as evidenced by the 10 percent per minute dispatch rate achieved by a gas-fired drum unit6.
For coal-fired power plants in the central and eastern U.S. that have installed NOX and SOX emissions abatement equipment, an opportunity for substantial CO2 reduction approaching 8 percent may be achieved by shifting from PRB coal to more local bituminous coal. The range of the shift to bituminous coal that is feasible is dependent on the design margin of the emissions abatement equipment, but can be expanded by the application of optimization technologies. Furnace optimization provides NOX reductions that can partially offset NOX increases resulting from the shift from PRB to bituminous coal while maintaining satisfactory furnace conditions. Soot blow optimization can help realign the shift in energy distribution resulting from coal blends to maintain unit thermal performance. Advanced steam temperature control strategies reduce steam temperature variability allowing faster ramp rates while reducing thermal stresses. This approach provides a near term opportunity for substantial CO2 reduction while enhancing unit dispatch capability.
1. Steam: Its Generation and Use, Babcock & Wilcox, The Babcock & Wilcox Co., 1978.
2. CSX web site: http://www.csx.com/?fuseaction=about.environment
3. Labbe, D., Roberts, D., Brown, J., “Equipment Upgrades and Phased Optimization Enhance Unit Performance,” 18th Annual Joint ISA POWID/EPRI Controls & Instrumentation Conference, Phoenix, AZ, June 2008.
4. Labbe, D., Coker, S., Speziale, A., “Energy Independence NOX/Heat Rate Optimization and Steam Temperature Control with Neural Net/Model Predictive Control Combo,” 15th Annual Joint ISA POWID/EPRI Controls & Instrumentation Conference, Nashville, TN, June 2005.
5. Labbe, D., Hocking, W., Ray, W., Anderson, J., Klepper, P., “Dynamic NOX/Heat Rate Optimization-Update,” ISA EXPO Conference, Houston, Texas, October 2006.
6. Labbe, D. Runkle, D., Lax, J., Chapa, R., “Optimizing Turbine Life Cycle Usage and Maximizing Ramp Rate,” 16th Annual Joint ISA POWID/EPRI Controls & Instrumentation Conference, San Jose, Calif.,June 2006.