At the University of Rochester in northwestern New York, a utility cogeneration plant provides electricity, steam, hot water, and chilled water to several internal customers, including the 154-acre, 158-building River Campus—the university's main center of learning—and the 750-bed Strong Memorial Hospital.

The plant has the capacity for instantaneous production of 23 MW of electricity, 550,000 lb of steam per hour, 250 million Btu of hot water, and 21,000 tons of chilled water. Electricity production is based on thermal and chilled-water load.

The plant's primary driver is Boiler No. 9. Installed in 2006, it feeds 900-psi super-heated steam at rates of up to 175,000 lb per hour to a turbine. The turbine is connected to an 11,500-VAC generator that can generate up to 16 MW of electricity. Natural gas is the boiler's primary fuel, but it also is capable of using No. 2 fuel oil. The turbine’s condensate loop, which provides thermal energy to the university's district heating loop, is capable of producing 175 million Btu.

Installed in 1967 and converted to gas operation in 1996, coal-fired Boiler No. 6 produces additional steam during peak demand. Along with three other dual-fuel boilers, it provides backup in the event the No. 9 boiler fails or is out of service for maintenance.

Better Control?
Air is supplied to the No. 9 boiler through a 480-VAC, 500-hp forced-draft (FD) fan. The university was having difficulty achieving rated boiler output partly because of an inability to maximize the capabilities of the FD-fan motor. A soft starter was used to start the FD-fan motor. The distributed control system (DCS) that controls the No. 9 boiler also controlled the pneumatic actuators that drove the inlet dampers of the FD fan.

The No. 9 boiler was designed to run at a high firing range. However, the damper control prevented the boiler from performing as designed and operating efficiently during the shoulder months of spring and fall. Additionally, a considerable amount of vibration and noise was created in the vicinity of the FD fan because of poor air-path conditions.

To improve the situation, the university decided to install a variable-frequency drive (VFD) to operate the FD-fan motor.

The VFD was built to meet the application's specific needs and installed during a scheduled power outage. During the process of integrating the VFD with existing controls, the boiler's damper sequence was discovered to be incorrect. The damper to the wind box located on top of the boiler was not opening sufficiently, causing a restriction in airflow and excessive vibration.

When demand increased, the boiler was starved for air because the FD fan could not keep up. Often, the fan ran at maximum capacity. The wind-box-damper situation was corrected, allowing the university’s most efficient boiler to produce steam at full capacity.

Automation System and VFD Work in Concert
The boiler-combustion control logic operating the VFD and FD-fan motor is metered-flow tie-back, cross-limited with excess-air correction.

Commissioning of the VFD went smoothly, the biggest challenge being matching accel and decel times to the process. With the VFD, the FD-fan motor responds better than ever to speed-command changes. The university was particularly impressed with the VFD's ability to recover quickly after a power-loss fault. The VFD is able to rapidly speed search and catch the coasting motor with minimal delay.

Lower Costs, Less Maintenance, Improved Operations
The university's cogeneration plant has run continuously and without issues since the VFD was installed. Both the VFD and the FD fan have operated reliably and efficiently.

Over a 50-day period prior to the VFD’s installation, the plant consumed 383,087 kwh of electricity while producing 141,093,563 lb of steam. Over a 50-day period following the VFD’s installation, the plant consumed 217,000 kwh of electricity while producing 139,988,998 lb of steam (Table 1). Thus, electrical consumption decreased by about 43 percent, with steam output remaining relatively constant.