Repowering is a Cost-Effective Option for Retired Coal-Fired Capacity

Jonathan C. Backlund, Joseph A. Barsin, Coen Company Inc.

Aaron Stanhope (System Engineer), Consumers Energy Company


There is now a major economic incentive for utilities owning retired coal fired capacity to consider conversions to natural gas and or oil. The older, smaller, high heat rate coal- fired units were retired because it was not practical five years ago to invest the capital required to bring these older units to BACT NOx condition. The spot power sales market, for example, on June 8, 2000 at $6000/MW, now provides a strong economic incentive to meet spot power sales. Converting these units to natural gas firing is a low capital method of making them available for peak service and gaining a rapid (less than 2-year) payback. This type of project is referred to as “REPOWERING” and the Consumers Energy Company’s B.C. COBB’s Unit 2 project is typical. This presentation reviews the Consumers Energy Company’s B. C. Cobb Station where its 67 MW Unit 2, originally fired by pulverized coal, was retired in 1990 after 42 years of service. This unit was “repowered” by natural gas and brought back into service in 1999 for peak- only service. Unit 2 was placed on line in April 1999, on schedule, and in good time to meet the summer peaks. NOx production was below guaranteed values allowing additional days of profitable peak power production under the total tons permit. The “repowering” was considered a complete success and one year later, in April of 2000, Units 1 and 3 were also retrofitted with the same excellent results.

This presentation reviews the operational period from its return to service through March of 2001.


Units 1, 2 and 3 at Consumers Energy Company’s B.C. Cobb Station, Muskegon, Michigan, were placed into service in 1948 and designed to fire pulverized coal using the tangential firing system and oil igniters. Each of the three units utilized burner tilt to control superheat final steam temperatures. Main steam was provided at 900 psig and 900 F to the 67 MW steam turbine generator. Heat rate was about 14,000 BTUs/kWh.

They were retired from service in 1990 due to the combination of low heat rate (inefficient) and the significant investment that would have been required to meet new lower gas and particulate emission standards. The 1996 peak summer load, actual vs. forecast, indicated to Consumers Energy that the possibility of selling summer peak power was real and an evaluation should be undertaken concerning the possibility of converting one of these units to “peaking” service. Because it was designed only for coal fuel at maximum continuous rating ( MCR), questions arose as to whether the unit could be “repowered” at a competitive cost to show a reasonable payback.

A natural gas line was already in the plant providing gas for the igniters in Units 4 and 5 and permitting those units to carry up to 40MW. The evaluation was completed in 1997 and the decision to convert Unit 2 to peaking service was made. The economic justification was based upon obtaining 700 operational hours per year at 1997 $/MW hour sales rates. Permits were obtained, however, that limited the tons of NOx to 39 tons total on a 12- month base rolling average. Thus the length of permitted generation/maximum power was tied to the projected NOx levels of 0.15lbs/NOx/106 BTUs total tons. Assuming a thermal efficiency of 85% approximately 871 x 106 BTUs per hour were required to produce 67 MWs. At 0.15 lbsNOx/106 BTUs about 131 lbs of NOx per hour was projected to be emitted. Full load emissions would permit 25 days x 24 hours or 600 hours.

In September of 1998, Coen Company was selected and awarded a turnkey contract to retrofit Unit 2 with a low NOx gas firing system. Project scope included computational fluid dynamic furnace modeling, gas ignition system, low NOx gas burners, fuel gas piping, flame detectors, a distributed control system for burner management as well as overall boiler control, field installation of the equipment and commissioning.

Unit 2 was placed on line in April 1999, on schedule and in good time to meet the summer peaks. NOx production was below guaranteed values.


Combustion System

The project duration that Coen committed to was eight months from release to on-line operation. This period included the CFD studies, design, fabrication, demolition of existing coal pipes, burners and oil lines, as well as installation of the new equipment. Coen was also responsible for the gas piping for the three units.

The conversion of a small unit originally designed for coal but now to be capable of MCR on natural gas, with the aim of achieving low NOx, was unique and Coen decided to model the process using computational fluid dynamics (CFD). The modeling indicated that for optimum NOx reduction two methods of staging should be used: first, on a level-to-level basis using the traditional over fire air (OFA). However, in this application three levels of OFA are used. And the second, at the individual burners using variable nozzle tips. On the level-to-level basis, the air is admitted into the furnace in two fuel air compartments, three auxiliary air compartments, and two over-fire air compartments, as shown in Figure 1.

Figure 1, One Corner Elevation of the New Burner

The individual burner staging is achieved with nozzle drillings that are fashioned to create the desired air staging. At higher levels of heat input, the combustion process undergoes an increase in fuel-air staging. As the flames from each corner of the furnace mix in the center, a single flame, the so-called “fireball”, is formed. The fireball itself then generates within the furnace (Fig. 2), another air-deficient zone. The circulation of the fuel around the fireball slows the mixing of reactants. As a result, air and fuel zones can be found at all stages of mixing.

Figure 2, Cross Section of a Tangential Fired Furnace

The original burner design used three levels for coal input, with air injected above and below each level. The CFD modeling indicated that the fuel elevations could be reduced to two; thus, for gas the compartments were reduced to two. Now new low NOx burners create internal staged mixing to further enhance the NOx reduction. The redesign was successful in reducing NOx while, at the same time, preventing furnace rumble. Furnace rumble had been a common occurrence when applying retrofits. Reference 1.

The “repowering” permitted applying the latest in gas igniters– specially designed NFPA-defined Class 2 natural gas-fired horn igniters– for each gas burner. Equipped with high energy igniter spark systems, each horn contained a flame-proving system with ionic flame rods, manual isolation valves, local double block and vent safety shutoff valve assembly and flexible stainless steel hose to bring the system up to NFPA minimums. All ignition system components are designed for easy removal and replacement, if required. The horns are constructed of 310 stainless steel to withstand the rigors of exposure to the flame and radiant heat of the furnace.

Controls and Instrumentation

The units had been manually controlled and had to be partially automated to make the peaking role effective and to insure that the low NOx staging would be automated and thus sustainable. Airflow, pressure regulation, and valve positioning were among the processes that had to provide feedback for control by the Westinghouse Distributed Control System (DCS). These devices did not exist and had to be added.

Retrofitting an upgraded Burner Management System (BMS) and the Combustion Controls in the DCS hardware contributed to the creation of a system with extensive operational advantages. DCS hardware selection, architectural considerations, system design, and integration of ancillary equipment were key engineering elements of the conversion. The design of the DCS included redundant fiber optic data highway, historical data storage and retrieval, with all the components residing in 16 cabinets. For the three units, the operator interface included 12 operator CRTs, along with one engineering console with two CRTs. A new flame scanning system for main flame detection was installed using the Coen IR7200A Viewing Head and IR7000B signal processor and is of the self -checking design, integrated with the BMS. Individual control actuators were installed for the forced draft fan, induced draft fan, and individual windbox compartment dampers. The control of air being introduced into the furnace was, of course, essential for the proper staging of combustion. These control devices permitted the total airflow to the furnace and its distribution to be monitored and maintained.


In the two years since the repowering what has been the experience?


Emissions were well below the restrictive “repowering” limits required by the EPA. At the time of project evaluation, they were 0.15 lbs NOx/106 BTUs which in turn permitted greater MW generation than that utilized in the economic analysis and thus improved plan payback to less than one year. Actual NOx achieved and maintained is 0.07 lbs. NOx /106 BTUs. The current NOx unit limit is 0.10 lbs NOx/106 BTUs, a limit that all three repowered units can meet with no additional modifications.

Heat Rate

The boiler thermal efficiency decreased, as expected on gas, with the higher water vapor loss offset to a slight amount by the lower excess air levels. Air heater surface had deteriorated during the 9-year shutdown and, in retrospect, it should have been replaced as a part of the repowering but, in fact, was delayed until success was demonstrated. The leakage reduced MCR to 61 MW (from 67 now achieved with good seals).


Because start up of the unit is still very much manual operator- intensive, a 16- hour- notice minimum is required to get the unit from cold to on line. This includes scheduling people in to work these units and is the major delay. In a modern day high pressure boiler, the drum metal rate of temperature change sets the cold start fire rate. If the unit is on hot standby, with turbine seals established, the firing time on gas to MCR is greatly reduced compared to the time taken when coal was utilized for a warm start and MCR could be carried within two hours.

In 1999 due to a hot summer Unit 2 operated 24 hours per day, five days per week, from June through September and generated 27,114 megawatt hours. Revenue generated from this retired unit exceeded several millions of dollars. In 2000, a cooler summer, Unit 2 now operating with “repowered” Units 1 and 3 operated somewhat less frequently.

Capacity Factor

Capacity factor (CF) calculated in the accepted manner was 7.6% for 1999 (only Unit 2) and 3.3% in 2000 for Units 1, 2, and 3. If the CF were calculated on the peak demand (desired time in service for these units) for 1999, it would be approximately 71% (5 days at MCR for 24 hours, 2 days at 0 load for 24 hours).


Budget constraints for the Unit #2 repowering forced deferment of several desired maintenance projects. Existing equipment such as the economizers are old and were affected by the 9 year out- of- service period. They do occasionally fail while the unit is in service, of course, and the unit must be shut down to effect a repair. Turbine, generator and condenser are all operating well, at 53 years of age. The boiler feed pump has some seal and motor problems. Unit 2 availability in 1999 was 90.2% and the availability of all three units in 2000 was 77.4%

Availability of Natural Gas

A one-mile pipeline had been constructed by the local gas supplier (10-inch) to provide natural gas for Units 4 and 5 igniters and partial load capability. Unit 2 repowering was able to use this same gas supply after the line was updated to higher capacity with new compressors. Units 1 and 3 required a new gas line of 12 inches.

The authors suspect that if a ten-mile line had had to be constructed, the local gas utility might not have been able to justify the cost.

Repowering Design & Equipment

The repowering system, including the burners, staging, igniters, BMS, controls, local actuators, and feedback devices, have all met or exceeded expectations.

Validity of Initial Justification

Under the projected NOx emissions, Unit 2 would have been limited to 600 operational hours. Unit 2 could have operated for more than 1,289 hours at full load, double the time used in the economic justification, because the actual NOx was lower than the predicted NOx; thus, the forecast vs. the actual was 200+% better. The payback was so attractive that the decision was made to “repower” Units 1 and 3 immediately and upgrade Unit 2’s air heater surface and insulation at the same time (Figure 3).

Figure 3, B.C. Cobb Power Station


In this case, Consumers Energy Company made the decision to “repower” a retired coal- fired asset and returned from retirement 3 x 67 MWs to provide peak power and profitable production. The project was fast tracked within an 8- month schedule from start to finish. The achievement of lower- than-predicted NOx by Coen Company’s turnkey retrofit improved the payback by 200% and exceeded all expectations.


1-Backlund, J.C., Cruz, E.R. and Stanhope, A., “Repowering a 60 MW Tilting Tangential Coal Fired Unit with A Low NOx Natural Gas Combustion System”, March 2000, Technical Proceedings Electric Power Conference, Cincinnati, OH.