|The GE LM6000 Aeroderivative Gas Turbine. Photo courtesy of GE.|
By James DiCampli, P.E., GE Distributed Power
Gas turbine fuel costs, even for efficient combined cycle plants, can be more than 80 percent of the cost of electricity over the life of the plant. Historically a niche segment, utilities, marine and industrial plants are increasingly seeking options to run lower cost alternative fuels. New technologies and applications have been developed to meet the growing demand for fuel flexibility.
Natural gas is the principal fuel of the aeroderivative gas turbine. Natural gas is a clean fuel and relatively inexpensive when compared to most fossil fuel options such as diesel or kerosene. There are many other gas and liquid fuels that can also be burned with minor gas turbine modifications and/or fuel cleaning.
Fossil fuels are not going to be replaced in bulk anytime soon. Global commerce and power generation depend on fossil fuels. Biofuels are growing through mandates in the transportation sector, but they are only price competitive when subsidized. Synthetic gas fuels have also gained popularity, but they are not available in volumes that would support world’s energy needs. Still, there are fuels of opportunity that make economic and in some cases, social sense. This article explores those fuels, and the challenges and solutions associated of utilizing them for aeroderivative gas turbine power generation.
Ethanol derived from sugarcane in Brazil or from other sources such as corn in the U.S. is one of the most efficient biofuels in terms of energy balance and carbon emissions. Almost 80 percent of the ethanol produced in the world today is used as fuel, primarily by land-based vehicles. Less than 10 percent of the world’s ethanol production is used in the beverage industry, and approximately 10 percent is used in industrial products such as paints, medicines and solvents. Ethanol production was about 22.7 billion gallons in 2010 compared to 19.5 billion gallons in 2009, a greater than 16 percent increase. Figure 1 shows how fuel ethanol has grown over the years while beverage and industrial use ethanol has remained fairly constant.
Two GE LM6000PC aeroderivative gas turbines have been converted at a power plant in Brazil to run on ethanol. Located in southern part of Minas Gerais, approximately 180 kilometers north of Rio de Janeiro, this 87-MW simple-cycle power plant was converted from a natural gas-only plant to a dual fuel, ethanol capable plant. This enhances the plant’s energy security and reliability by providing a valuable alternative fuel source when natural gas is not available. This is the world’s first use of sugarcane-based ethanol in a gas turbine system to produce electricity on a full commercial scale.
The goal of the project was to assess gas turbine performance in terms of emissions, efficiency and component durability when fueled with ethanol. The demonstration consisted of 975 hours of testing (actual gas turbine operating time on ethanol), including load variation, water injection variation, fuel transfers between natural gas and ethanol, and startup and shutdown of the gas turbine on ethanol. The demonstration included interim borescope inspections, and at the conclusion of the demonstration, the gas turbine was disassembled for a detailed component inspection. The performance of the gas turbine was equivalent to the same gas turbine operating on natural gas and the emission levels of sulfur dioxide (SO2), aldehydes, carbon monoxide and unburned hydrocarbons were very similar. Nitrous oxide (NOx) emissions were reduced when compared distillate fuels, and all the carbon emissions were from renewable sources. Hot section component deterioration was comparable to distillate fuel operation for the same run time.
To reach full designed power, about 1.6 times more ethanol flow is required compared to diesel, given the lower volumetric energy content of ethanol. The ethanol used is hydrous, meaning that it contains 6 perccent to 10 percent water. The increased water content is actually beneficial, cooling the combustion temperature and resulting in lower NOx emissions.
This site drew international attention when then President of Brazil, Mr. Lula da Silva, attended the site’s inauguration to highlight that Brazil’s ethanol could be used for clean power generation.
Biodiesel is derived from plants (jatropha, rapeseed, palm, algae, etc.) or animal fat by products; all having a varied amount of C14-C22 saturated and unsaturated fatty acids. The production process is called transesterification: the oil in the presence of a base catalyst is reacted with alcohol (usually methanol) to form methyl esters, with glycerin as a by-product. Biodiesel contains practically no sulfur and no aromatics (toluene, benzene, etc.). Relevant biodiesel specifications include ASTM D6751, and European Specification EN 14214.
Diesel made from crude oil (petro-diesel) is a mixture of hydrocarbons, while biodiesel is a mixture of unsaturated fatty acid esters. Biodiesel has a detrimental effect on elastomers commonly found in many of the gaskets and sealants in a typical gas turbine package, so care must be taken in selecting compatible components. The heating value of biodiesel is less than that of diesel by about 10 percent; to get the same power output fuel flow to the combustor must be increased by that amount.
One of the better qualities of biodiesel is its lubricity; it can be used as an additive to improve the lubricity of most fossil fuels such as ultra-low sulfur diesel. It also burns cleaner and creates about 60 percent less net carbon dioxide emissions in diesel engines, inclusive of the plant growing cycle and associated CO2 absorption.
With the above considerations, biodiesel is an excellent alternative fuel for aeroderivatives.
Marine Application: GE marine customers have periodically run LM2500+ gas turbines on biodiesels, some for a period of 6 to 12 months, when it is price competitive to marine gas oil. When fossil fuel prices receded and biodiesel prices increased, the ships returned to their normal use of fossil fuels. The ships remain capable of running either fuel, or blends, and can switch pending the price of fuel.
Industrial Power Plant: A power plant in New York conducted a biodiesel fuel demonstration on a GE LM6000PA gas turbine in 2007. Today, biodiesel continues to be used as a backup fuel for the plant. The purpose of the demonstration was to evaluate effects on load variation, emissions and operability. The combined cycle plant produces 105 MW when its two LM6000PA’s are running along with a 25 MW steam turbine. The biodiesel used for this test met GE and ASTM D6751 specifications and had a LHV of 16,250 BTU/lb. No changes were made to the engine or package for this demonstration. The gas turbine was started on biodiesel and shut down on biodiesel without any issues. NOx emissions were found to be about 5 ppm lower for biodiesel operation than for diesel operation, while requiring less water injection for NOx abatement. Carbon monoxide emissions were lower as well for biodiesel. A borescope inspection of the hot section of the turbine showed the internal parts to be cleaner after biodiesel operation. Exhaust filters were also shown to be significantly cleaner after biodiesel operation.
Distributed Power Plant: An east coast university demonstrated biodiesel on its boilers and a GE LM1600 gas turbine. Emission components tested were carbon monoxide (CO), nitrous oxide (NOx), non-methane hydrocarbons (NMHC), total suspended particulates (TSP) and PM10. The turbine was initially started on gas and then transferred to biodiesel, but was eventually started and shut down on biodiesel as well. Fuel heating was not required for this testing, but could be an issue at this site while operating during winter months. Without modifications, the unit was not able to reach full power as the fuel control valve reached its full stroke at about 13.5 MW (LM1600 can produce 14 MW). A higher flow fuel control valve would allow this turbine to reach base load.
The power generation technology of tomorrow will demand fuel flexibility. As such, biogas or hydrogen-based fuels will increasingly be in the mix for gas turbine simple and combined cycle power plant operations.
Hydrogen-containing fuels can come from various sources. Certain industrial processes form by-products, such as coke oven gas, which are attractive options for gas turbine applications since they are “free.” The gasification of coal or biomass provides a precombustion solution for reducing carbon dioxide emissions, leaving a high hydrogen syngas fuel.
Another source of hydrogen-based fuels is the power-to-gas application where excess power from renewables is used to electrolyze water to hydrogen and oxygen. This is one possibility to store abundant energy, and one that will be important for future networks where a high amount of renewables calls for a balance between volatile energy production and consumption.
Until recently, most hydrogen experience has been in the petro-chemical industry, utilizing by-product gases such as excess hydrogen from steam reforming. Table 1 summarizes GE’s aeroderivative turbines’ commercial experience with hydrogen in gaseous fuel.
From 1986 until just recently, the LM5000 package (33 MWe, ISO conditions) in Germany operated on various mixes of methane with up to 50 percent hydrogen. Other packages include the LM2500 (22MWe) in the U.S. and Brazil, and the LM6000 (42 MWe) in the U.S. and Japan.
For pre-mixed, dry-low emissions (DLE) combustion systems, the hydrogen content is limited to 5 percent by volume. The limit is due to fast flame speeds from high hydrogen fuels that can result in flashback or primary zone re-ignition. For single annular combustor (SAC, or diffusion flames) systems, limits range from 35 percent hydrogen by volume for larger turbines (up to 100 MWe), to about 85 percent by volume for smaller turbines in the 18 MWe to 30 MWe power range. Engineering factors include combustor geometry, airflow, and cooling patterns.
GE recently introduced the LM2500+ and +G4 series of aeroderivative gas turbines for operation on coke oven gas (COG) as fuel for power generation. The LM2500 is an ideal fit for COG applications because it requires minimal changes and best fits power demand and available COG at typical coking facilities. COG has very high hydrogen content (up to 65 percent by volume) and contains many by-products such as BTX (benzene, toluene, and xylene), naphthalenes, tar, sulfur compounds and alkali metals. With the right fuel treatment, conditioning and fuel delivery system, COG fuel used in a gas turbine is both a cost-effective solution and significantly reduces the environmental impact of the steel making process. The first two GE aeroderivative COG units entered commercial service in the summer of 2011; they generate 60 MW in a combined cycle configuration.
High hydrogen fuels pose ignition risks when initiating the flow of gas and following the termination of the flow of gas to the gas turbine. Non-combusted fuel can exist above the lower explosion limit (LEL) in the gas fuel circuit, which in the presence of oxygen creates the potential for igniting within a confined volume. This risk is mitigated by using a CE/ATEX certified inert gas system to purge the gas fuel circuit prior to initiating the flow of fuel. The CE/ATEX also purges any remaining fuel following the termination of the flow.
Another consideration is the absorption of hydrogen into metals that can cause a general loss of ductility, or hydrogen embrittlement. Hydrogen will diffuse through most materials and can collect in “dead” cavities. This creates an explosive hazard with the potential to shorten component life. Gas path materials and components must be selected with appropriate specification criteria.
Since natural gas fuel reserves are often located remotely from major centers of demand, there is a global need to transport it. Around one-third of the natural gas internationally traded is transported in a form of liquefied natural gas (LNG)3, and this fraction is projected to grow.
LNG is a mixture of gases, predominantly methane, liquefied at a temperature of -262 °F (-163 °C). The feedstock gas is first processed to remove hydrogen sulfide (H2S), carbon dioxide (CO2) and water vapor (H2O) to desirable levels by absorption, adsorption and separation processes. These contaminants are undesirable as they will freeze in the very low temperature cooling processes. H2S is also a toxic, corrosive, acid (sour) gas; CO2 is also acidic (sour) and corrosive in the presence of water.
Heavier fractions are removed as well, including propane, butane and ethane commonly referred to as natural gas liquids (NGLs). Aeroderivatives can be fueled with either LNG or NGLs. Re-gasified LNG can be used in either pre-mixed, dry low emissions or diffusion flame combustion systems with no turbine/package modifications required. NGLs may also be utilized, and pending the ratios of the hydrocarbons present, may be used in either gas or liquid form. More on this later.
The resulting fuel derived from LNG after regasification is extremely pure. As such, it meets the requirements of the standard GE Aeroderivative’s fuel specification and is suitable for combustion in either premixed (dry low emissions) or diffusion type combustion systems in aeroderivative gas turbines, and no engine/package modifications are required. Table 2 summarizes compositions of processed LNG produced by different LNG facilities.
Recently GE announced that two LM2500 turbines, capable of generating 59,000 horsepower, were installed on a 325-foot passenger and vehicle ferry. The ship carries LNG, which is re-gasified on board to fuel the engines. Marine grade oil is also used to start the engines and as a backup fuel. The wave piercing catamaran can travel at a speed of over 58 knots (67 miles per hour) while running on natural gas. The ferry will operate between Buenos Aires, Argentina and Montevideo, Uruguay, shuttling up to 1,000 passengers and 150 cars between two ports.
LNG Plant Application
For LNG plants, the reliability of gas turbines used for power generation or as mechanical compressor drivers remains critically important to plant economics. Another valuable feature is the ability to operate on process-off gas streams. If gas streams with elevated content of nitrogen or CO2 could be injected into the gas turbine instead of being stripped from inert in nitrogen/CO2 rejection units, this would increase the overall efficiency of the plant and bring considerable operating and capital expense savings.
Over the last few years, GE Aero has executed a series of engine tests with fuels of medium BTU content and fuels of varying composition, demonstrating that such fuels can be successfully burned, and that the turbine combustion systems can manage significant gas composition variability. The successful demonstrations lead to GE Aeroderivative selection for mechanical drive for major LNG facilities, currently in the build phase.
As discussed, heavier fractions can be removed from natural gas, consisting primarily of ethane, propane and butane, commonly known as Natural Gas Liquids (NGL). NGLs may be burned in aeroderivative gas turbines, and pending the ratios of the hydrocarbon components, are utilized as a fuel in either a liquid or gas phase.
The key consideration is the hydrocarbon dew point and bubble point temperature as a function of pressure. At given pressure, a fluid having temperature higher than its dew point remains entirely in the gas phase. Similarly, the bubble point is the highest temperature at which given composition of the fluid is entirely liquid at given pressure. Fluid having the temperature between its dew and bubble point at given pressure will be a two-phase mixture.
For continuous and reliable operation, gas turbines may operate on either gas or liquid fuel with appropriate fuel delivery systems. For this reason, GE Aero has developed a set of temperature limits for condensates, which ensure that given fuel remains in the same phase when flowing through the entire fuel delivery system. Table 3 below summarizes these requirements.
Two examples below illustrate how fuel composition and dew and bubble point properties influence the possibility to run aeroderivatives with single annular combustor systems on condensate-type fuels in either gas or liquid phase. Compositions are given in table 4 below.
Both Figures 2 and 3 illustrate how dew point and bubble point temperatures change differently with pressure due to different fuel compositions. Fuel temperature requirements from Table 3 define the operational area (pressures and temperatures) at which given stream may be used either as a gas or as a liquid.
Condensate B has much “broader” distribution of hydrocarbons, compared to Condensate A. Because of that, it would need to be super-cooled to operate it safely as a liquid. Aeroderivatives require high fuel pressures (specific to the given engine model). At such pressures, condensate B requires more super-cooling than A to maintain it in the liquid phase.
Naphtha-type liquid fuels have similar compositions and physical properties as condensates. GE Aero has multiple gas turbines operating on “light” liquid fuels far more different than the standard distillate fuel diesel #2. LM6000 engines alone have more than 450,000 hours of cumulative experience on naphtha.
To utilize condensates as fuels, the package and engine fuels system and configuration may require some level of customizations. These are briefly summarized in the list below:
- Start-up on “standard” fuel such as diesel or natural gas
- On engine equipment and hardware including dual fuel nozzles, primary manifold, pressurization valve kits and parts.
- Gaseous purge system
- Components and piping to purge gas fuel manifold with CDP air when engine is operating on liquid fuel
- Liquid fuel drain piping and components
- Upgraded control system hardware and software
- Condensate fuel forwarding skid
- Condensate boost pump skid
- HP water injection skid
- Low-pressure fuel filter skid
- Vent fans in area of fuel metering valves
Aeroderivative gas turbines continue to exhibit the excellent performance on standard fuels such as natural gas and petro-diesel. There is a growing global demand to burn alternative fuels of opportunity that would lower the cost of gas turbine operation and/or improve emissions.
1. Dr. Christoph Berg, F.O. Licht, “World Fuel Ethanol – Analysis and Outlook”
2. EIA, Annual Energy Review, Oct. 2011
3. BP Statistical Review of World Energy, Jun. 2012
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