1. Field of the Invention
This invention discloses methods whereby the emissions of nitrogen oxides, NOx, from existing combustion gas turbines that have little or no NOx reduction controls can be reduced.
2. Description of Prior Art
Electricity demand varies hourly, daily and seasonally with peak demand occurring during mid-day, during the summer air conditioning season. Simple cycle gas turbines are especially suited to meet this peaking demand due to their relative simplicity and rapid startup capability, and they have been used for decades for this purpose. However, increasingly stringent limitations on the emission of nitrogen oxides from older gas turbines with little or no nitrogen oxides, NOx, emission controls have resulted in their retirement or limited their use to power production emergencies with annual operating limits ranging from several 10's of hours to several 100's of hours. However, in times of extended power shortages, such as has occurred in California in 2000 and 2001, government authorities have allowed these turbines to be placed into service for as much as several 1000 hours annually, provided the high NOx emissions are offset with lower emissions from other NOx producing industrial machinery, or by payment of an extremely high NOx emission fee. While this waiver makes it economical to operate gas turbines with some NOx control, it is prohibitively expensive to operate turbines having no NOx control. For example, according to NOx emission data published by the Environmental Protection Agency (EPA) under the Acid Rain Emission Program, oil fired, simple cycle, peaking turbines in the 10 to 100 megawatt output range with no NOx controls emit about 0.4 to 0.5 lb/MMBtu. Similar size turbines without NOx controls fired with natural emit between 0.3 to 0.45 lb/MMBtu (equal to 200 to 330 part per million (ppm) at 3% O2.
There is, therefore, a need for a simple, low cost method or methods that allows the addition of NOx reduction equipment to these turbines and extend their use in peaking power applications.
As described by Lefebvre (Arthur H. Lefebvre, “Gas Turbine Combustion”, [McGraw-Hill Company, New York, 1983]), in prior art, water droplets or steam has been injected into the combustion chamber of a gas turbine, fired either with natural gas or liquid petroleum fuels, to increase the power output, and to reduce the combustion gas temperature, thereby suppressing the formation of thermal NOx. However, lowering the combustion temperature increased the formation of carbon monoxide, CO. For example, NOx reductions of over 90% have been achieved with a factor of about ten increases in CO, which replaces one pollutant, NOx, with another, CO, (Lefebvre, FIG. 11.18, Page 483.) In the case of heavy residual fuels, which have substantial fuel bound nitrogen, water injection is to some extent counterproductive because the NOx yield from fuel bound nitrogen increases.
A very key curve (Lefebvre, FIG. 11.22, p.487) shows the importance of controlling the primary combustion zone for a hypothetical combustor meeting the 1977 automotive NOx emission standard. For optimum NOx reduction, the gas temperature must be within a very narrow range between 1600° K, below which CO increases rapidly above 70 ppm, and 1730° K, above which NOx increases rapidly above 5 ppm. This shows the importance of selecting the proper water injection location for controlling NOx. In a handbook published in 1976 by the South Coast Air Quality Management District, Los Angeles area, Calif., NOx reductions to 30 ppm at 3% O2 with water injection are reported for a 32 MW electric output Pratt & Whitney (P&W) peaking turbine. The NOx emission was 330 ppm at 3% O2 for a 17 MW P&W turbine without injection. No CO data was given.
Lefebvre shows (FIG. 1120, p.485) that injecting the water with the combustion air is much less effective in reducing NOx compared to injecting directly into the primary combustion zone. A 75% reduction was obtained in a military aircraft (Reference 44, page 511) at a water/fuel ratio of unity in the latter case versus about 40% reduction in the former case.
Statler (U.S. Pat. No. 5,784,875, Jul. 28, 1998) offers a recent example, including prior patents, of the typical prior art by which water droplet injection was practiced to reduce NOx and increase power output. The common element in this prior art is that injection takes place in, or near, the fuel injection location. For example, for dual liquid fuel, natural gas fired combustors, the water droplets are injected in the natural gas fuel passages when fuel oil is the only fuel. If natural gas is the fuel, then separate water injection tubes located near the gas fuel injectors are used. Since water droplets lower the gas temperature, this increases unburned hydrocarbons and CO formation,
Steam injection, instead of water, has also been used to reduce NOx in prior art, (H. E. Miller, “Development of the General Electric Quiet Combustor”, GER 3551, Mar, 8, 1988). In the GE F7001 gas turbine, 25 ppmv (at 15% O2) NOx emissions with natural gas and 55 ppmv (at 15% O2) with fuel oil, were achieved. However, steam may be unsuitable for simple cycle, peaking turbines, which may not have access to high-pressure steam from a boiler. Also, it has the same deficiency as water injection near the fuel inlet in that unburned hydrocarbons and carbon monoxide will increase. In addition, it is more difficult to assure uniform mixing of the steam and combustion gas to yield uniform gas temperature reduction and reduce NOx.
Staged combustion is another NOx reducing method, in which part of the combustion takes place in a pre-combustor chamber at fuel rich conditions, which occurs at a lower gas temperature and inhibits NOx formation. The resultant gases flow into the main combustion chamber where they mix with the bulk of the air for final combustion (Lefebvre, pages 491–497). Miller (GER3551) cites a combustor design using this staged combustion method that also achieved 25 ppmv NOx emissions at 15% O2. Apparently this latter method cannot be combined with steam injection, presumably because staged combustion already lowers the gas temperature to the range where thermal NOx is mostly suppressed. The staged combustion method for gas turbines is also called “Dry Low NOx Emission, DLN”. For example, such a method is used in the LM Series of commercial gas turbines of the General Electric Company that are rated at 13.7 to 47.3 MW output. However, instead of a single pre-combustion chamber, (as described by Lefebvre, pages 491–497), the combustion products from several dozen small pre-combustion chambers, arranged in a circle at the upstream end of the main combustion chamber, exhaust into primary chamber, for final combustion with the bulk of the combustion air. This GE turbine yields a nominal 25 ppm NOx and 25 ppm of CO at 15% O2 with natural gas and 42 ppm NOx with oil.
Also, Schorr (M. M.Schorr, “Gas Turbine NOx Emissions”, GE Company Document GER 4172, September 1999) states that recent large utility scale GE turbines can achieve NOx levels as low as 9 ppm at 15% O2 with DLN. Other gas turbine manufacturers supply similar “dry” staged combustion systems. The GE system can be retrofitted to earlier LM turbines by replacing part of the combustion chamber. This procedure is very complex and costly. Schorr also notes that the Selective Catalytic Reduction, SCR, process, which is placed at the turbine exhaust and can achieve the lowest NOx levels reported to date, namely 5 ppm, or less, is not suitable for simple cycle turbines because the exhaust temperatures are too high for the catalyst. They are primarily suited for combined cycle application. He also notes that even minute quantities of sulfur in the fuel can have very detrimental impact of the SCR system. It is also to be noted that the SCR process is much too costly for peaking turbines that are used for short periods each year.
Older gas turbines were equipped with un-cooled metal turbine wheel blades that cannot withstand direct contact with the combustion gases whose temperatures are well in excess of 2000° F. Even modem turbines with cooled blades cannot operate with gas temperatures above 3000° F. Consequently, part of the compressor air is directed to regions downstream of the primary combustion zone to cool the combustion gases to temperatures compatible with turbine materials. Lefebvre (Chapter 1), and Statler (U.S. Pat. No. 5,784,875, FIG. 1) show typical combustion chamber designs. In fact, Jennings and Rogers (B. H. Jennings & W. L Rogers, “Gas Turbine Analysis and Practice”, McGraw-Hill, N.Y., 1953, FIG. 9–11, page 386) show that the basic design concepts for gas turbine combustors have not changed since the invention of the modem gas turbine in the 1930's.
FIG. 1 consists of a combustor 1 having an outer housing 2 that encloses an inner perforated metal combustor liner 3 having numerous slots, and fewer circular and rectangular openings of various sizes 4 around its circumference and along its axial length through which compressed air 5 enters the combustion zone 61, and combustion gas cooling zones 7 and 8, each immediately downstream of the other. The liquid fuel from injector 6 or gas fuel from injector 12 mix with part of the compressor air 5 in zone 61 to effect most of the combustion at stoichiometric air fuel ratios slightly greater than one and achieve the peak combustion gas temperature. Most of the thermal NOx form in this zone. Additional compressor air enters through the other openings 4 downstream of zone 61 to mix with the primary combustion gases in zone 7 and zone 8 to cool the combustion gases to a temperature low enough to be compatibility with turbine wheel materials. In the prior art water or steam were injected through ports 11 located near fuel inlets 6 or 12. If only liquid fuel is used, the water droplets were in some prior art injected through the gas tubes 12.
Prior art, including the several references cited above, teaches that demineralized water should be using with water or steam injection because some of the constituents in untreated water contain chemicals, such as alkalis, that can deposit on downstream turbine components, such as the turbine wheel, and damage said components. However, for peaking turbines, which are generally older units operating at lower peak temperatures, regular water may be acceptable. The turbine wheels can be cleaned between operating periods. Furthermore, many of these peaking turbines use fuel oil, which also contains undesirable chemicals that require their periodic removal during the shutdown periods.
Another related area is the chemistry of NOx formation. Liquid fuels suitable for gas turbines contain small levels, typically less than 1%, of nitrogen in the fuel. The combustion of said liquid fuels under excess air conditions leads to the formation of fuel bound NOx. In solid fuels, namely coal, the three primary NOx precursors that are released in the combustion of fuel bound nitrogen are hydrogen cyanide, HCN, ammonia, NH3, and nitrogen oxide, NO. In fuel rich combustion, these three species are converted to nitrogen. Many researchers have measured the rate of destruction of these species under fuel rich conditions, (e.g. J. W. Glass and J. O. L. Wendt, “Mechanisms Governing the Destruction of Nitrogenous Species During Fuel Rich Combustion of Pulverized Coal”, in Proceedings 19th Symposium (International) on Combustion, [The Combustion Institute, Pittsburgh, Pa. 1982] p.1243). These rates can be used to approximately estimate the time required to reduce these three species by a specific amount, such as a factor of 10. It was found that as the stoichiometric ratio approaches unity, i.e., proceeds from very fuel rich to fuel leaner conditions, the concentration of NO predominates and the other two species are sharply reduced, (see for example, Y. H. Song, et.al., “Conversion of Fixed Nitrogen in Rich Combustion”, in Proceedings 19th Symposium (International) on Combustion, [The Combustion Institute, Pittsburgh, Pa. 1982] p.53). Therefore, a conventional fuel lean combustor will produce almost completely NO species.
Calculations were performed for the time needed for a factor of 10 reduction of NO in a Western U.S. coal, using Glass' reaction rates, for two fuel rich stoichiometric ratios of 0.5 and 0.7, i.e. 50% and 30% oxygen deficiency, respectively. Initial concentrations of NO at these stoichiometric ratios were taken from D. P. Rees, et.al., “NO Formation in a Laboratory Pulverized Coal”, ”, in Proceedings 19th Symposium (International) on Combustion, [The Combustion Institute, Pittsburgh, Pa. 1982] p.1305). It was found that temperature was the primary rate governing factor. At 2000° F., a factor of ten reductions required several seconds, while at 2500° F., it required about 0.1 seconds, and at 3000° F., about 0.01 seconds, for both 50% and 30% oxygen deficiency. These calculations apply to combustion at atmospheric pressure. The reaction rates will be much more rapid in gas turbine combustors which operate at high gas pressures. Therefore, a small gas combustion zone where the stoichiometry is slightly fuel rich, such as 10% fuel rich, may be sufficient to convert fuel bound nitrogen to N2. This may account for part of the substantial NOx reduction observed in gas turbine combustors having pre-combustion chambers.
On the other hand, at atmospheric pressure and temperatures of about 3000° F., and higher, thermal NOx form in significant quantities at excess air conditions. Again at the higher gas pressure in gas turbine combustors, thermal NOx formation will form in significant quantities at temperatures below 3000° F. Water or steam injection into this higher temperature zone has been widely used in prior art to lower the combustion gas temperature and inhibit thermal NOx formation. However, water or steam injection will not be effective with fuel bound NOx.
However, another process, called selective non-catalytic reduction, SNCR, can be used to reduce NOx derived either from thermal or fuel bound reactions provided the reaction takes place in a specific gas temperature range. SNCR involves the injection of a reagent, primarily urea or ammonia, into the combustion gases in a boiler furnace at temperatures of about 1700° F. to 2000° F., where the NOx to N2 reaction is favored. This method can achieve in excess of 50% NOx reduction. However, it is essential to inject the reagent into the proper gas temperature zone in order to minimize un-reacted NH3 carryover from the combustion chamber exhaust into the turbine wheel, where it can react with copper based materials as are found in turbine bearings, and out of the exhaust, where it becomes an atmospheric pollutant. Furthermore, if a liquid fuel is used in the gas turbine and it contains sulfur, any left over NH3 will react with sulfur gas to form liquid compounds that can deposit on metal surfaces downstream of the combustion chamber. It is, therefore, essential to limit and consume the ammonia in the appropriate gas temperature reaction zone of about 1700° F. to 2000° F. For the gas turbine application this gas temperature zone will generally be downstream of both the primary combustion zone and downstream of the water or steam injection zone.
For NOx reduction by liquid droplet injection throughout the appropriate combustion gas temperature zone in the furnace section of a boiler, Zauderer used (U.S. Pat. No. 6,048,510, Apr. 11, 2000) a droplet injector that produced droplets of varying size that contained urea or ammonia, and vaporized throughout the gas temperature zone of 1700° F. to 2000° F. This SNCR method reduced NOx emission by up to 50% in the furnace of a boiler.
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