By Ian Summerside

Figure 1: PSM’s LEC-III Combustion System cross section. To date, the PSM fleet of these low emission systems has surpassed 1.5 million hours and over 18,000 starts in more than 70 units. They can achieve sub-4 ppm NOx emissions over a pre-mix operating range with low CO, combustion dynamics and turndown from base load operation[/caption]

In the United States, the EPA’s most recent Clean Power Regulation requires power plant operators to reduce ozone-causing gas turbine (GT) emission levels. To comply, power plant operators are aggressively evaluating cost and performance strategies to ensure profitable operation.

Options typically include shutting down or selling facilities, procuring emission credits in the marketplace, changing the turbine’s operational profile, replacement of combustion systems with more modern technology and installation of Selective Catalytic Reduction (SCR) systems.

The decision-making process is driven by complex plant and company-wide risk-based, cost-benefit analyses that determine the selection of the best plant and company-wide approach. Mature turbine life extension assessments, for example, must consider a diverse set of factors, such as projected plant use, turbine operational experience, regulatory dynamics and overall costs in order to properly evaluate future profitability. Life extension substantiation can be further complicated by changes in environmental and economic conditions, coupled with the shifting nature of governmental and corporate strategy.

Best available technology

Improvements in the technology of dry, lean pre-mix combustion systems for GTs are seen as the Best Available Technology (BAT) to provide a reduction in NOx emissions without the use of diluents or an SCR at the exhaust stack. This type of combustion system can provide a cost-effective method of addressing emissions requirements.

A plant supplying peak power to the Federal Energy Regulatory Commission (FERC) regional northeast U.S. power market in the northeast U.S. faced such a challenge in 2013. A High Energy Demand Day (HEDD) regulatory mandate stated that the plant had to reduce its NOx emission to less than 10 ppm and CO emission to less than 80 ppm between 80% and 100% load for ambient temperatures above -11°C (10°F). Those requirements were relaxed to 12 ppm and 100 ppm, respectively, below -11°C (10°F), and between 90% and 100% load. The new regulations were to come into force in 2015. This plant consists of 4 x 1 Frame 7B gas turbines units, configured to run in combined cycle or simple cycle with an exhaust bypass stack. Originally commissioned in 1974, each unit produces about 49 MW in simple cycle mode. The GTs were configured with diffusion flame combustions systems with water injection as a diluent to control NOx creation.

For mature turbines already using steam or water injection for NOx abatement, the choices in meeting more stringent emissions regulations are currently limited to converting the combustion system to a lean pre-mix design, improving or adding SCR capability, or replacing the turbines with more modern equipment. Due to the design limitations of the plant’s existing exhaust system equipment, coupled with packaging constraints making SCR installation impractical, it was concluded that a retrofit of the combustion systems would be the best option based on life cycle cost, installation schedule and overall implementation complexity. The operator decided to convert the 7B gas turbines from high-NOx emitting diffusion combustion systems to ultra-low NOx combustion system technology.

Conversion scope

PSM’s LEC-III technology was first incorporated into GE Frame 7E gas turbines in 1998. This can‐annular, reverse-flow combustion system (Figure 1) was designed to be a direct replacement into an existing GT outfitted with the OEM DLN1 system. The hardware scope of supply included combustion liners, end covers, primary fuel nozzle assemblies, secondary fuel nozzles (SFN), flow sleeves, transition pieces and bullhorn brackets, cross fire tubes, clips and spool pieces, combustion stub cases, combustion dynamics monitoring system (CDMS) and an NERC-compliant monitoring & diagnostic server. In addition, the project entailed a new gas-fuel skid (including piping and manifolds), combustion ignition and flame detection system, and flame scanners (redundant primary flame zone and secondary flame zone).

Coverting old logic

Finally, the original OEM GT control system was decommissioned and a new system was installed both for gas turbine control and the BOP. The old control logic was reprogrammed. This included logic for the ultra-low emission combustion system and fuel skid, engine protection and associated auxiliaries (flame scanner detection system, CDMS and Inlet Guide Vane control).

While typical conversions on Frame 7B/E, 7E and 7EA are relatively straightforward, there is added complexity and challenges when applying the technology to low firing, mature 7B GTs. Prior to this project, this technology had been implemented on GTs with firing temperatures ranging from 1,075°C to 1,150°C (1,965°F to 2,100°F).

However, this 7B is fired at 1,000°C (1,840°F), 52°C (125°F) colder than the lowest-fired, ultra-low emission combustion unit. This called for precise metering of the air flow entering the combustor to achieve NOx and CO targets while maintaining sufficient margin for elevated combustion dynamics and Lean Blow-Out (LBO).

This was accomplished by sizing the combustor to obtain a Reaction Zone Temperature (TRZ) that is similar across all combustion system configurations, regardless of frame size and firing temperature.

The relatively low turbine inlet temperature meant that the 7B burnt gas temperature profile inside the combustor and transition piece showed a severe drop of about 426°C (800°F) between the TRZ and the turbine inlet temperature (TIT). As a consequence, the amount of dilution air injected between the TRZ and the turbine inlet was greater than for any other Frame 7E equipped with this system. The dilution air is typically injected at one plane at the aft end of the liner, and one-to-three planes inside the transition piece.

Design analytics identified the optimum set up. Computational Fluid Dynamics (CFD) helped to understand the mixing and dilution of the air inside the transition piece, and the impact on the TIT profile. The retrofit and commissioning of the first unit occurred in June 2014. The second and third units were completed in October 2014 while the fourth and last units were finished in January 2015.

The new combustion system lowered oxygen and corrected NOx emissions from 35 ppm to around 3 ppm across the desired operating range, while CO emissions fell from up to 100 ppm to between 9 and 25 ppm.

Stringent regulations

Emissions regulations are forcing power plant operators to make emission reduction decisions. In each case, it is critical to analyze any number of technologies to ensure business requirements and objectives are met. While the example provided here is a solution for the 7E and 7EA low-emissions market, developing and implementing a similar design for older, low-firing GTs opens up a new market by keeping these assets economically and environmentally viable.

The results from this conversion, as well as field experience at other sites with this type of technology have demonstrated the ability to achieve sub-4ppm NOx emissions with margin across the entire load range along with acceptable levels of dynamics and extended combustion inspection intervals up to 32,000 fired hours. Furthermore, a positive trade-off can be realized between achieving low CO emissions through “late” dilution with no impact on gas turbine life.

Author: Ian Summerside is Global Product Line Manager at Power Systems Manufacturing (PSM). Ultra-low emission combustion systems from PSM are available and operating within GE Frame 6B, 7B/E/EA and 9E machines on nearly 70 gas turbines as well as two W501D5 and four W501B6 units, having accumulated over 1.5 million hours of successful operation. For more information visit