The primary pollutants from gas turbines are oxides of nitrogen (NOx), carbon monoxide (CO), and volatile organic compounds (VOCs). Other pollutants such as oxides of sulfur (SOx) and particulate matter (PM) are primarily dependent on the fuel used. The sulfur content of the fuel determines emissions of sulfur compounds, primarily SO2. Gas turbines operating on desulfized natural gas or distillate oil emit relatively insignificant levels of SOx. In general, SOx emissions are greater when heavy oils are fired in the turbine. SOx control is thus a fuel purchasing issue rather than a gas turbine technology issue. Particulate matter is a marginally significant pollutant for gas turbines using liquid fuels. Ash and metallic additives in the fuel may contribute to PM in the exhaust.
It is important to note that the gas turbine operating load has a significant effect on the emissions levels of the primary pollutants of NOx, CO, and VOCs. Gas turbines typically operate at high loads. Consequently, gas turbines are designed to achieve maximum efficiency and optimum combustion conditions at high loads. Controlling all pollutants simultaneously at all load conditions is difficult. At higher loads, higher NOx emissions occur due to peak flame temperatures. At lower loads, lower thermal efficiencies and more incomplete combustion occurs resulting in higher emissions of CO and VOCs. See the previous discussion of NOx formation in (section 4.2.3).
The focus of turbine NOx control and combustion improvements of the past decade was to lower flame hot spot temperatures using lean fuel/air mixtures and pre-mixed combustion. Lean combustion decreases the fuel/air ratio in the zones where NOx production occurs so that the peak flame temperature is less than the stoichiometric adiabatic flame temperature, therefore suppressing thermal NOx formation.
Lean premixed combustion (DLN/DLE) pre-mixes the gaseous fuel and compressed air so that there are no local zones of high temperatures, or “hot spots,” where high levels of NOx would form. Lean premixed combustion requires specially designed mixing chambers and mixture inlet zones to avoid flashback of the flame. Optimized application of DLN combustion requires an integrated approach to combustor and turbine design. The DLN combustor becomes an intrinsic part of the turbine design, and specific combustor designs must be developed for each turbine application. While NOx levels as low as 9 ppm have been achieved with lean premixed combustion few DLN equipped turbines have reached the level of practical operation at this emissions level necessary for commercialization – the capability of maintaining 9 ppm across a wide operating range from full power to minimum load. One problem is that pilot flames, which are small diffusion flames and a source of NOx, are usually used for continuous internal ignition and stability in DLN combustors and make it difficult to maintain full net NOx reduction
over the complete turndown range.
Noise can also be an issue in lean premixed combustors as acoustic waves form due to combustion instabilities when the premixed fuel and air ignite. This noise also manifests itself as pressure waves, which can damage combustor walls and accelerate the need for combustor replacement, thereby adding to maintenance costs and lowering unit availability.
All leading gas turbine manufacturers feature DLN combustors in at least parts of their product lines. Turbine manufacturers generally guarantee NOx emissions of 15 to 42 ppm using this technology. NOx emissions when firing distillate oil are typically guaranteed at 42 ppm with DLN and/or combined with water injection. A few models (primarily those larger than 40 MW) have combustors capable of 9 ppm (natural gas fired) over the range of expected operation.
The development of market-ready DLN equipped turbine models is an expensive undertaking because of the operational difficulties in maintaining reliable gas turbine operation over a broad power range. Therefore, the timing of applying DLN to multiple turbine product lines is a function of market priorities and resource constraints. Gas turbine manufacturers initially develop DLN combustors for the gas turbine models for which they expect the greatest market opportunity. As time goes on and experience is gained, the technology is extended to additional gas turbine models.
The primary post-combustion NOx control method in use today is selective catalytic reduction (SCR). Ammonia is injected into the flue gas and reacts with NOx in the presence of a catalyst to produce N2 and H2O. The SCR system is located in the exhaust path, typically within the HRSG where the temperature of the exhaust gas matches the operating temperature of the catalyst. The operating temperature of conventional SCR systems ranges from 400 to 800° F. The cost of conventional SCR has dropped significantly over time — catalyst innovations have been a principal driver, resulting in a 20% reduction in catalyst volume and cost with no change in performance.
Low temperature SCR, operating in the 300 to 400 ° F temperature range, was commercialized in 1995 and is currently in operation on approximately twenty gas turbines. Low temperature SCR is ideal for retrofit applications where it can be located downstream of the HRSG, avoiding the potentially expensive retrofit of the HRSG to locate the catalyst within a hotter zone of the HRSG.
High temperature SCR installations, operating in the 800 to 1,100° F temperature range, have increased significantly in recent years. The high operating temperature permits the placement of the catalyst directly downstream of the turbine exhaust flange. High temperature SCR is also used on peaking capacity and base-loaded simple-cycle gas turbines where there is no HRSG.
SCR reduces between 80 to 90% of the NOx in the gas turbine exhaust, depending on the degree to which the chemical conditions in the exhaust are uniform. When used in series with water/steam injection or DLN combustion, SCR can result in low single digit NOx levels (2 to 5 ppm).
SCR systems are expensive and significantly impact the economic feasibility of smaller gas turbine projects. For a 5 MW project electric generation costs increase approximately half a cent per kWh. In addition, SCR requires on-site storage of ammonia, a hazardous chemical. Finally, ammonia can “slip” through the process unreacted, contributing to environmental health concerns.
