At this point in time, everyone is “for the environment” and this is true the world world over because the atmosphere is shared by peoples of all nations. Air pollution from hydrocarbon fuel combustion, both worldwide and local, is discussed by reviewing known measurements of contaminants. Application of gas turbines by industry is one way to provide power needs for attaining and maintaining an industrial society. Environmental performance of industrial gas turbines with respect to exhaust emissions and environmental impact is presented for oxides of nitrogen, hydrocarbons, carbon monoxide, particulate matter and visible smoke. Results of recent abatement efforts are also presented together with estimates of potential improvements to show the place of the industrial combustion turbine in a world with growing concern for environmental improvement.

This paper presents the results obtained from a 1/8 th scale rich-quench-lean (RQL) combustor designed for ultra-low NOx operation running at Allison 501-K engine simulated full and part load conditions. The goal of the test program was to demonstrate the capability of the combustor to limit oxides of nitrogen (NOx) emissions to less than 10 ppmv and provide simultaneous control of carbon monoxide (CO) emissions to below 50 ppmv, both corrected to 15% oxygen. The tests were conducted on a refractory-lined bench scale combustor developed originally to support the advanced coal fired gas turbine program which is sponsored in part by the Department of Energy (DoE) Morgantown Energy Technology Center (METC). Measurements were made of NOx and CO emissions from natural gas (NG) and distillate fuel number 2 (DF#2) with water injection at simulated full and part power operation over a range of rich, quench and lean zone temperatures. The results show that the NOx goals of the test program were met and that CO emissions could be further controlled to less than 10 ppmvd on both fuels. The thermodynamic constraints of the system, the airflow splits and water injection rate requirements are discussed together with the combustor general design parameters. Estimates are also made for the required steam injection rate to produce the same NOx and CO emission levels.

This paper describes considerations that must be addressed when designing a gas fuel clean up system to meet utility gas turbine fuel specifications. Each gas turbine manufacturer has a gas fuel specification that must be met in order to protect the equipment from the effects of burning poor quality gas fuel. With the introduction of advanced technology combustion systems and strict emission requirements, it has become increasingly important that clean, dry gas fuel be provided at the inlet to the gas turbine control system in order to maintain the equipment in proper working order. The ASME gas fuel standard B133.7M is representative of a specification that meets or exceeds most manufacturer’s requirements. This specification calls for superheating to avoid the condensation of moisture or hydrocarbon liquids and includes limits on particulate concentration and size. Issues relating to the fuel quality are discussed, including calculation and measurements of dew points, gas sampling and analysis and relative location of cleanup equipment required to meet this specification.

The ASME Fuel Specification B133.7M [1] states that a typical margin of 25 to 30° C (45 to 54° F) of superheat is used for natural gas fuel but offers no basis for the estimate. The purpose of this paper is to propose a method for the safe determination of superheat that is less conservative, yet will meet the six sigma requirement of less than 4 defects (condensate formation) in one million opportunities. A drop in the total temperature of natural gas will be experienced as the gas expands in pressure reducing stations and across control valves. If the temperature falls below the hydrocarbon or moisture dew point, condensation will take place and liquids will collect or will be entrained with the gas. The temperature drop is inversely proportional to the pressure drop and is often termed ‘Joule-Thomson cooling’ or ‘J-T cooling’. The rate of cooling is described by the Joule-Thomson coefficient that can be determined by experiment or calculated from the gas composition. Superheating the gas prior to expansion can prevent condensation. The degree of superheat required for hydrocarbons, however, is often greater than the expected temperature loss across the valve as the hydrocarbon dew point may increase as the pressure falls. This paper describes a method for determining the quantity of superheat required for a specific gas composition and develops a general equation in terms of gas supply pressure that will satisfy the needs for the majority of natural gases. The general equation is based on the statistical analysis of superheat requirements for over 230 natural and liquefied natural gas compositions. A similar equation is also presented that describes the superheat requirements to avoid moisture condensation. The two equations can be used to specify the heating requirements upstream of pressure reducing stations or control valves.