O&M, Business – Brownsville CombustionTurbine Plant

The integration of operations, maintenance, and technical expertise enables a TVA 220 MW plant

Brownsville CombustionTurbine Plant

Tennessee Valley Authority 
490-MW, dual-fuel, simple-cycle peaking facility located in Brownsville, TN

Plant manager: Danny Clayton
Key project participants: Dean Frederick, site foreman; Carl Byrd, CT technician; Chris Ritchie, CT technician; Thomas Robertson, CT technician; Ron Willis, CT technician; Frank Herndon, machinist; Zach Cowart, outage and projects manager; Clinton Lafferty, senior systems engineer, Innovative Steam Technologies (IST); Wood Group GTS; Process Control Solutions LLC

Challenge.

Since commissioning in1999, two simple-cycle Westinghouse 501D5 gas turbines, each rated at110 MW with steam injection for emissions control, lacked operational stability when ambient temperatures were below 50F. Both units used once-through steam generators (OTSGs) mounted in the exhaust stack to make steam with a minimum of 50 deg F of superheat. When ambient temperatures fell below 55F, operators periodically had to manually control the steam system, and as temperatures dropped further, operations had to continuously control steam generation parameters to prevent OTSG trips and likely gas-turbine trips. Also, since the plant was originally designed as an economic summer peaking facility, feedwater start up control and freeze protection systems were missing or inadequate. During unit startup, control room and outside operators multi-tasked among feedwater flow rate, vent- and drain valve positions, and unit operating parameters to match steam and combustor pressure for steam injection; all with a likely risk of tripping a unit because of flame blowout. Previous attempts to tune the two units and adjust the control logic resulted in little to no improvements. With low reliability during cold weather, the units remained unavailable for generation during half of the year.

Solution.

Utilizing operation, maintenance, and technical expertise a comprehensive solution was developed focusing on these three major phases:

  • Gas turbine and feedwater controllogic enhancements.
  • OTSG efficiency improvements.
  • Critical instrument freeze-protection upgrades.

Originally, the GT variable inlet guide vanes (IGVs) opened at 25 MW, decreasing the exhaust temperatures and reducing OTSG efficiency. Utilizing a control methodology from combined-cycle operations, closed loop IGV controls provided enhanced exhaust-temperature stability and minimal impact to unit output or heat rate for small temperature changes. An outside engineering firm developed and implemented the enhanced IGV control logic and additional operator interfaces to improve steam generation startup and system stabilityduring ambient temperature changes.

In combination with IGV controls, a simple addition to the feedwater control logic allowed operations to quickly enable steam injection. The outside engineering firm implemented a feedwater offset bias and control graphic to allow the CRO greater control over the feedwater flow just before and at steam injection—thereby avoiding the need for continuous opening and closing of steam system drains and vents to match combustor pressure.

The control graphic was implemented with preset minimum and maximum values and change rates to allow flexibility but protect the OTSG. While control improvements had the potential to improve operation with ambient temperatures between 40 and 50F, achieving very cold weather operation during ambient conditions less than 30F required additional efforts on the steam generation system. Internal engineering studied these four alternatives:

  • Increasing OTSG thermal efficiency.
  • Adding exhaust-duct firing.
  • Maintaining higher feedwater temperature.
  • Enhanced IGV controls only.

Increasing OTSG thermal efficiency via increased surface area showed the greatest benefit for the dollars invested. Consequently, it resulted in the least plant disruption with regards to installing balance of plant systems or environmental permit reviews while allowing the units to operate in temperatures between 0F and 10F.

Upon selecting the concept, the plant owner obtained additional engineering support, component manufacturing, and field installation services from the OTSG OEM, which recommended changing fin pitch on the OTSG tubes from 5 fins per inch (FPI) to nine on two of the six rows of tubes for 23% additional surface area. The OTSG tube change out was completed during June and July.

The internal outage planning organization and OTSG OEM field service crews were able to complete the work ahead of schedule and on budget, allowing the plant to set new generation records. Finally, O&M personnel focused early in the projecton the lack of freeze protection on certain critical instruments. Plant personnel, along with an internal field services crew, installed insulated and heated instrumentation boxes around all water-containing pressure transmitters. With temperatures below normal in December 2010, additional issues were discovered with the existing feedwater and attemperator freeze protection, as well as instrument air systems. The plant’s engineering and maintenance resources quickly responded with freeze protection and piping insulation upgrades to sustain operations below 20F.

Results.

As the project phases were completed, the operational impact was immediate:

  • IGV control improvements maximized exhaust temperature and were easily enabled and disabled by the operators.
  • Feedwater control improvements reduced steam injection task duration from 5 to 10 minutes to 3 to5 minutes and allowed outside operators to focus on other unit startup tasks.
  • Additional 23% surface area in the OTSG increased steam temperature by more than 120 deg F, allowing the units to successfully operate at ambient temperatures as low as 10F with greater than 100 deg F of superheat.

Along with the critical instruments and more recent upgrades to the feedwater and attemperator freeze protection systems, the two units are providing 220 MW of previously unavailable generating capacity for project cost of less than $1 million.