By Leslie Witherspoon and Anthony Pocengal, Solar Turbines Inc.
As climate change initiatives and related programs and regulations continue to evolve so do gas turbine power generation markets and applications. From combined cycle natural gas power plants, to landfill gas and other alternative fuels, to on-site cogeneration, gas turbines are playing an increasingly important role in improving overall system efficiency while reducing greenhouse gas emissions profiles.
Historically, nitrogen oxides (NOX) have been the primary pollutants of interest from gas turbines. Regulations abound around the world limiting NOX emissions from gas turbines. Despite the current frenzy related to greenhouse gases (GHG), NOX emission requirements will likely continue to become more stringent. So as programs for both pollutants evolve, gas turbine manufacturers and users need to be involved so that gas turbines remain a preferred source of energy production.
This article focuses on gaseous fuel applications of mid-range industrial gas turbines (1 MW to 30 MW). This market continues to grow as facilities expand and seeks ways to improve system efficiency and reduce dependence on grid power by replacing older boiler plants with more efficient systems. Gas turbine-driven cogeneration systems (or combined heat and power plants) have numerous applications and a favorable environmental signature. Another growth market for gas turbines is with alternative fuels. However, as alternative fuels become more mainstream, understanding the impact on turbine operation, durability and emissions signature (both NOX and CO2) of various fuels and fuel blends is increasingly important.
Gas turbines were originally designed to operate using pipeline-quality natural gas, light distillate oil or both. Over the years, gas turbines have been successfully adapted through modifications to the combustion and control systems for operation on many gaseous and liquid fuels covering a wide range of physical and chemical properties. Advances in alternative fuel capability have been driven by the desire among customers to operate turbomachinery using the most economical fuel available.
One of the primary factors to determine fuel suitability for a particular application is combustor design. A critical element in using gas turbines (and which is often overlooked or misunderstood by regulators)is the relationship between the gas turbine fuel, the combustor design and the resulting emissions profile.
Gas turbine manufacturers generally offer two combustor design options on a specific turbine model: conventional (or diffusion flame) and dry low emissions (or lean pre-mixed) combustion.
The conventional combustion system uses diffusion flame combustion characterized by high flame temperatures and concurrent mixing and burning of the air and fuel within the combustor volume. Conventional combustion gas turbines exhibit excellent turndown with broad fuel flexibility. In most conventional combustors diluents such as water or steam can be injected directly into the flame for purposes of NOX emissions reduction.
The dry low emissions (DLE) combustion system uses lean premixed combustion to operate with low emissions of NOX and carbon monoxide (CO). With lean premixed combustion, the fuel and air are premixed before reaching the flame front at a reduced fuel-air ratio and corresponding reduced flame temperature.
While gas turbine systems can burn a wide variety of gaseous and liquid fuels, not all fuels that can be burned in a conventional combustion gas turbine can also be burned in a DLE gas turbine. Different fuels require different handling and control systems and, for the more radical fuels, redesigned combustion systems.
Gaseous fuels normally are classified by their Wobbe index, a parameter that accounts for variation in the fuel gas density and heating value. The Wobbe index is used to indicate changes required to the fuel system to accommodate fuels with different heating values. The Wobbe index relates relative heat input to a combustion system of fixed geometry at a constant fuel supply pressure. If two fuels have the same Wobbe index, direct substitution is possible and no change to the fuel system is required. The normal design criterion is that gases having a Wobbe index within +/- 10 percent can be substituted without making adjustments to the fuel control system or injector orifices.
Figure 1 illustrates the typical ranges of composition and Wobbe index for fuels with respect to combustion systems. Most of the fuels shown in the figure can be combusted in a conventional gas turbine with exception of the very lightest (Wobbe index <300). The center band identifies typical Wobbe index ranges of fuels that can be used by DLE gas turbines.
Research and development is ongoing to expand the lean premix Wobbe range in order to accommodate higher and lower Wobbe fuels. Figure 1 also graphically illustrates the wide Wobbe index range of a specific fuel as well as how the Wobbe index of various fuels overlap. Even though two fuels may have identical Wobbe indices their fuel compositions and thus emissions characteristics will vary.
Figure 2 further illustrates the variability of fuel composition in non-natural gas gaseous fuels. Shown at the top, pipeline natural gas is the baseline gas turbine fuel. Methane, ethane and propane along with hydrogen and carbon monoxide are the combustible species found in the alternative fuels. Landfill, digester, and raw gases are primarily methane diluted with CO2 and nitrogen. Gasified biomass, refinery gases and coal-derived gases all add hydrogen and some carbon monoxide to the mix.
Methane, ethane and propane burn in a predictable and controlled manner. Gas turbine combustion systems are generally designed to use these three gases as the primary fuel source. Hydrogen and carbon monoxide are more reactive and special system modifications need to be made as the percentage of these constituents increase. Carbon dioxide and nitrogen act to reduce the energy content of the fuel, increase the fuel flow rate requirements, and increase the risk of flameout.
Gas turbine systems have some of the lowest emission signatures and the highest efficiencies of all combustion sources. Despite this, there is an ever-increasing volume of gas turbine emissions regulations.
The primary target pollutants over the last 30 years from gas turbines have been NOX. Significant investment in research and development brought about lean premix combustion systems. Technology advancements have resulted in a 70 percent to 95 percent reduction in NOX emissions from natural gas-fired gas turbines over the last 15 or more years. It will be critical over the next decade that smart policy and regulations be developed without penalizing the already low emitting and efficient gas turbine.
Gas turbines have some of the lowest NOX emissions signatures of all prime movers. Typical NOX emissions from a new gas turbine installation are a factor of 10 less than from the average U.S. coal plant. NOX emissions from gas turbines firing natural gas range from 5 parts per million (ppm) to 250 ppm. Lower NOX emissions levels can be achieved with add-on control systems, such as selective catalytic reduction (SCR). Higher emission levels are predicted on some of the less traditional alternative fuels. Table 1 summarizes typical NOX emission ranges for some alternative gaseous fuels that are used with gas turbines.
In Figure 3, NOX emissions are normalized relative to what would be produced by pure methane (pipeline natural gas is the baseline). The underlying assumption is that the combustor design is unchanged for the different fuel types. In general, lower Wobbe index fuels with lower stoichiometric flame temperatures produce lower NOX emissions than fuels with higher concentrations of hydrogen and carbon monoxide and higher stoichiometric flame temperatures.
For example, NOX emission levels on a landfill gas turbine range from 25 to 80 ppm NOX depending on the fuel quality and turbine model. The low emissions levels are achievable due to the comparatively low British thermal unit (Btu) content (300 to 500 Btu/scf) of landfill gas. If natural gas (900 to 1,200 Btu/scf) were used in the same gas turbine, NOX emissions would range from 100 to 250 ppm.
CO2 and Gas Turbines
Burning a given amount of a hydrocarbon fuel results in the same amount of CO2 emissions, regardless of how the fuel is burned or which type of engine is used for the energy conversion. So while NOX emissions are significantly lower with DLE than with conventional combustion, the same does not hold for CO2. Carbon dioxide emissions from a conventional combustor and its DLE counterpart are essentially equal. Figure 4 summarizes CO2 emission rates for several fuels.
Gas turbines differentiate themselves from other combustion sources by high efficiency and total system efficiency; for example, combined heat and power (CHP) systems, coupled with comparatively low NOX emissions. Figure 5 summarizes approximate CO2 emission rates from several natural gas-fired gas turbine applications as compared to coal. Each natural gas application is based on around 117 lb/MMBtu. The different output-based CO2 emission rates are due to the typical system efficiencies of the various applications.
CHP systems are defined as thermal systems that produce both power and useful heat. They are an efficient and clean approach to generating power and useful thermal energy from a single fuel source. CHP systems are used either to replace or supplement conventional separate sources of heat and power. Every CHP application involves the recovery of otherwise wasted thermal energy to produce additional power or useful thermal energy.
In the industrial gas turbine range, typical CHP systems are selected based on process heat requirements. Where significant quantities of both power and process heat are required, gas turbine cogeneration systems often provide the most economical solution. If excess power can be sold to the electric utility/grid at a reasonable rate, or if supplemental firing is used, then the quantities of power and process heat can be generated independently of one another, allowing for additional system flexibility.
While thermodynamic considerations will identify the best equipment selection from a performance perspective, an economic evaluation will determine if the expected profits or cost savings for a given project justify the capital expenditure. Relatively independent of the economic evaluations is the emission signature. An important emerging variable in the evaluation of a CHP plant is its CO2 emissions signature. The adoption of programs that monetize CO2 emissions could alter the traditional “how and when” operation of a CHP plant when fuel prices and/or electricity prices would otherwise dictate buying electricity from the grid and operating package boilers vs. operating the CHP plant.
By using waste heat recovery technology to capture a significant proportion of the waste heat, CHP systems typically achieve total system efficiencies of 60 percent to 80 percent for producing electricity and thermal energy. Because CHP is more efficient, less fuel is required to produce a given energy output that with separate sources of heat and power. Higher efficiency translates into lower operating costs, reduced emissions of all pollutants, increased reliability and power quality, reduced grid congestion and avoided distribution losses.
Combined heat and power systems also offer considerable environmental benefits when compared with purchased electricity and on-site generated heat. Because less fuel is combusted, greenhouse gas emissions, such as carbon dioxide, as well as NOX and SO2 are reduced. Figure 6 estimates NOX emissions savings of CHP over a typical natural gas generation system at 29 tons a year.
The challenges to implement CHP across the world include fuel costs and project economics. Utility interconnection and stand-by charges, as well as regulatory constraints and economic barriers to the economically based export of power from CHP facilities to the grid also significantly influence the success of proposed cogeneration projects. Properly designed, future GHG policy and regulation can remove some of the traditional hurdles for CHP implementation. By comparison, CHP projects in the European Union typically do not face as many regulatory hurdles as CHP in the United States and thus are much more widespread.
Waste Gas Utilization
Methane emissions from vented landfills represent a frequently lost opportunity to capture and use a significant energy resource. Where landfill gas is still vented, capturing the gas and installing a gas turbine has the dual advantage of eliminating methane emissions while providing often much needed electricity.
Though flaring of landfill gas (LFG) is beneficial in converting methane to CO2, useful energy is lost. Converting landfill methane to energy in a gas turbine can maximize the environmental benefits of an otherwise wasted energy source.
As GHG programs develop, policies and regulations for converting currently vented or flared landfill (and digester) gas systems to clean power generation facilities, including as turbine systems, should be one of the cornerstones of the programs.
Historically, both reciprocating engines and conventional gas turbines have been used in landfill gas applications. A recent addition to the landfill gas market is the Mercury 50. Generally, lean premix combustion systems have not been compatible with landfill gas. However, the Ultra Lean Premix (ULP) combustion system on the Mercury 50 has been modified to support landfill gas combustion.
An example was developed to illustrate the benefits of applying gas turbines in landfill gas applications. Carbon dioxide equivalent emissions, NOX emissions, and power production from hypothetical landfills are compared. The example looks at four landfill scenarios.
Landfill A: Landfill gas is vented to the atmosphere
Landfill B: Landfill gas is captured and flared
Landfill C: Landfill gas is captured and burned in a reciprocating engine
Landfill D: Landfill gas is captured and burned in a gas turbine.
Landfill gas flow is assumed to be 1,500 scfm. The landfill gas fuel composition is assumed to be 52 percent methane, 40.6 percent carbon dioxide, 7.2 percent nitrogen and 0.2 percent oxygen. Nitrogen oxides emissions from the flare are estimated at 0.1 lb/MMBtu (HHV). The reciprocating engine NOX emissions are estimated at 45 ppm. The gas turbine NOX emissions are estimated at 25 ppm.
As shown in Table 2, Landfills B, C and D have a significantly lower greenhouse gas impact compared to Landfill A. Landfill A vents 8,688 tons a year of methane directly to the atmosphere with a Global Warming Potential (GWP) of 21 times CO2. Thus, when the methane is converted to its CO2 equivalent (CO2e)—8,688 tpy x 21—and added to the CO2 that vents directly to the atmosphere, Landfill A has five times the GHG impact as Landfills B, C and D.
The NOX emission impact comparison between a flare and gas turbine is relatively neutral, while the reciprocating engine case emits more NOX. Looking at useful energy, Landfills C and D provide the most. Even though the flare has relatively low NOX emissions, it provides no useful energy compared to both the reciprocating engine and gas turbine.
It is important that emerging GHG policy and regulations be structured to promote the production of useful energy from waste fuels. The ability to develop an electric power project at a specific landfill depends largely on the regional wholesale power purchase rate and the ability to actually secure a power sales contract for a “small” project and the associated utility interconnection requirements. For example, the development of landfill gas-fired electric power projects in large portions of the U.S. is hampered by wholesale power purchase rates or by a cumbersome procurement structure that makes it difficult for small projects to obtain power sales agreements. With the advent of renewable portfolio standards, renewable power sales markets are rapidly changing.