(41h) Clean Combustion of Liquid Biofuels in Gas Turbines for Renewable Power Generation

Clean Combustion of Liquid Biofuels in Gas Turbines

for Renewable Power Generation

M. Klassen, M. Ramotowski, L. Eskin, and R. Roby

LPP Combustion LLC, Columbia, MD, USA,

1        Introduction

Traditionally, spray diffusion combustors have been employed in gas turbines that operate on liquid fuels, including conventional fuels such as fuel oil #1 and fuel oil #2, also renewal fuels such as ethanol or biodiesel.  However, this diffusion mode of operation tends to produce unacceptable levels of NO_x emissions.  The current technology for burning liquid fuels in gas turbines is to use water and/or steam injection with conventional diffusion burners.  Emissions levels for a typical ?state of the art? gas turbine, such as a GE 7FA burning fuel oil #2 in diffusion mode with water/steam injection, are 42 ppm NO_x and 20 ppm CO [ REF _Ref156787028 \r \h 1].  Water/steam injection has a dilution and cooling effect, lowering the combustion temperature and thus lowering NO_x emissions. But at the same time, water/steam injection is likely to increase CO emissions as a result of local quenching effects.  Thus, the ?wet? diffusion type of combustion system for liquid fuels must trade off NO_x emissions for CO emissions.

In recent years, stringent emissions standards have made lean, premixed combustion more desirable in power generation and industrial applications, since this combustion mode provides both low NO_x and CO emissions without water addition.  Lean, premixed combustion of natural gas avoids the problems associated with diffusion combustion and water addition and is the foundation for modern Dry Low Emissions (DLE) gas turbine combustion systems.  When operated on natural gas, DLE combustion systems provide NO_x and CO emissions of 25 ppm or less.  However, these systems cannot currently operate in premixed mode on liquid fuels because of autoignition and flashback within the premixing section [3]. 

In this study, vaporization of the liquid fuel in an inert environment has been shown to be a technically viable approach for LPP combustion.  As described in this paper, the fuel vaporization and conditioning process [2] was developed and tested to achieve low emissions comparable to those of natural gas while operating on liquid fuels.  Tests conducted in both atmospheric and high pressure test rigs utilizing typical swirl-stabilized burners  found operation similar to that achieved when burning natural gas [3].  Emissions levels were similar for both the LPP gas fuels (fuel oil #1 and #2) and natural gas, with any differences in NO_x emissions ascribed to fuel-bound nitrogen present in fuel oil #2.  Extended lean operation was found for the liquid fuels due to the wider lean flammability range for these fuels compared with natural gas. An added advantage is the ability to achieve fuel-interchangeability of a natural gas-fired combustor with liquid fuels.  This was described in much greater detail in recent papers [3, 4].

2        LPP Process

In this approach, liquid fuel is vaporized in an inert environment to create a fuel vapor/inert gas mixture, called LPP gas, with combustion properties similar to those of natural gas.  Premature autoignition of the LPP gas was controlled by the level of inert gas added during the vaporization process.  Tests conducted in both atmospheric and high pressure test rigs utilizing typical swirl-stabilized burners (designed for natural gas) found operation similar to that achieved when burning natural gas.

3        Biofuels Testing

Biofuels testing of the LPP Combustion System was performed in an atmospheric pressure combustor rig using a Solar Turbines Centaur 50 natural gas nozzle.  The same commercial gas burner hardware was used for both natural gas and liquid biofuels, as LPP gas, without any modification (Figure 1).  The biodiesel used for testing was soy-oil based soy-methyl-ester (SME).  Figure 2 shows the atmospheric pressure test facility used to evaluate various fuels using the LPP Combustion Technology. Combustor inlet temperatures were maintained at typical compressor discharge temperatures of 600 K to 630 K. 

Figure 1: Lean, premixed natural gas flame (left) and lean, premixed, prevaporized biodiesel flame (right)

Figure 2: Atmospheric pressure combustor test facility used to evaluate emissions for various fuels using LPP Combustion Technology.

Figure 3 shows a comparison of NO_x emissions obtained for biodiesel and ethanol with those of natural gas, fuel oil #1 and fuel oil #2.  The biodiesel and ethanol emissions are similar to those obtained from natural gas and fuel oil #1 and are lower than the NO_x emissions obtained from fuel oil #2 which contained some fuel bound nitrogen.  The results for the biofuels are expected since both biodiesel and ethanol contain no significant fuel-bound nitrogen. 

Figure 3: Comparison of NO_x emissions for natural gas, fuel oil No. 2, fuel oil No. 1, biodiesel (soy methyl ester, SME) and ethanol (ASTM D-4806).

Figure 4 shows a similar comparison of CO emissions obtained for biodiesel and ethanol with those of natural gas, fuel oil #1 and fuel oil #2.  This Figure shows that the biofuels also produces very low CO emissions when burned lean, premixed and prevaporized using the LPP Combustion technology. 

Figure 4: Comparison of CO emissions for natural gas, fuel oil No. 2, fuel oil No. 1, biodiesel (soy methyl ester, SME) and ethanol (ASTM D-4806).

The big benefit of burning biofuels, such as biodiesel or ethanol, is that the emissions are considered to be ?carbon neutral? or ?net zero? [5, 6].  This designation takes into account the complete carbon cycle of the fuel including the growing cycle of the plant used as a feedstock to make the biofuel.  As the plant grows, it consumes CO₂ from the atmosphere.  When the plant is burned as a biofuel, the CO₂ is liberated back to the atmosphere as a ?net? zero contribution to the atmosphere.

Conventional application of biofuels to gas turbines for the generation of renewable energy encounters the same emissions limitations on NO_x and CO as conventional petroleum fuels [7, 8].  The emission results from burning liquid fuels using LPP Combustion technology show a significant improvement over the 42 ppm NO_x level for liquid fuel operation.  Gas turbine plants permitted for liquid fuel operation are typically restricted, based on emissions, to approximately 500 hours of annual operation.   Since the LPP Combustion technology achieves low emissions for liquid fuels, this allows for significant additional run time under a plant's existing air permit. 

Figure 5 shows a comparison of various combustion technologies used for large scale power production.  California and other states have adopted an emissions performance standard (EPS) for carbon dioxide emissions of 1,100 lb CO₂/MWh [9].  Conventional boilers have low thermal efficiencies and produce significant carbon emissions.  Both natural gas and oil fired combined cycle gas turbines can meet the 1,100 lb CO₂/MWh.  However, for practical purposes, conventional liquid fuel-fired gas turbines are severely restricted on annual hours of operation due to criteria pollutant emissions (primarily NO_x).  LPP combustion technology could achieve the 1,100 lb CO₂/MWh EPS and not be restricted on annual operation.

Several clean coal technologies such as integrated gasification combined cycle (IGCC) and coal to liquids (CTL) derived from the Fischer-Tropsch process can achieve natural gas criteria pollutant levels, but still require carbon capture and storage (CCS) in order to meet the 1,100 lb CO₂/MWh EPS.

Figure 5: Summary of net CO₂ emissions from various power generation sources

Since the combustion of biofuels is considered to be carbon neutral, the amount of carbon in the earth's atmosphere remains unchanged, thus costly post combustion carbon capture and storage is not required.  Burning biodiesel or ethanol using the LPP Combustion technology achieves both natural gas level emissions for criteria pollutants and no net carbon emissions and thus represents the cleanest use of renewable fuels for power generation.

references

1.       Davis, L. B. and Black, S. H., 2000, ?Dry Low NOx Combustion Systems for GE Heavy-Duty Gas Turbines?, GER 3568G.

2.       Roby, R. J., Klassen, M. S. and C. F. Schemel, 2006, ?System for Vaporization of Liquid Fuels for Combustion and Method of Use?,
U.S. Patent, #7,089,745 B2.

3.      
Gokulakrishnan, P., Ramotowski, M. J., Gaines, G., Fuller, C., Joklik, R., Eskin, L.D., Klassen, M.S., and Roby, R.J., ?A Novel Low- NO_x, Lean, Premixed Prevaporized Combustion System for Liquid Fuels?, ASME Turbo Expo 2007, Montreal, Canada, May 14-17, Paper GT2007-27552.

4.       Ramotowski, M. J., Roby, R.J., Eskin, L.D., and Klassen, M.S., ?Fuel Flexibility for Dry Low Emission Gas Turbines ? Cleanly Burning Biofuels, Coal Liquids and Petroleum Fuels?, PowerGen Conference and Exposition 2007, New Orleans, LA., USA, December 10-13.

5.       ?
Kyoto Protocol To The United Nations Framework Convention On Climate Change?, 1998, United Nations Publication.

6.       Lewis, C., 2006, ?A Gas Turbine Manufacturers View Of Biofuels?, Rolls-Royce Company Presentation.

7.       Moliere, M., Panarotto, E., Aboujaib, M., Bisseaud, J. M., Campbell, A., Citeno, J., Maire, P. A. & Ducrest, L., 2007, ?Gas Turbines In Alternative Fuel Applications: Biodiesel Field Test?, ASME Turbo Expo 2007, Montreal, Canada, May 14-17, Paper GT2007-27212.

8.       Henderson, B., 2007, ?Duke Energy Tries Biodiesel Blends?, The Charlotte Observer, The News & Observer Publishing Company.

9.       Collord, Gary, ?Implementation of SB 1368 Emission Performance Standard?, 2006,
California Energy Commission, Report Number CEC-700-2006-011.