Gas turbines require clean gas to operate efficiently. Particulate contamination fouls fuel nozzles, causes increases in flue stack emissions, and occasionally causes unplanned plant outages. Now a new real-time natural gas cleanliness monitoring and web-based alarm system is providing valuable protection for natural gas–fired power plants. The adaptation of laser light–scattering technology for the purpose of contaminant measurement in high-pressure gaseous pipelines provides a method of monitoring liquid and solid contamination levels.
In order to protect gas turbine (GT) power generation facilities against the threat of particulate contaminant, plant operators install fuel gas conditioning systems. Additionally, plant personnel at natural gas–fired power plants rely heavily on gas sales contracts to ensure that purchased natural gas is tariff quality.
Even with these safeguards in place, contaminant-related performance problems can take GTs off the grid. Fuel gas conditioning systems typically fail due to poor design or equipment malfunction. And gas sales contracts do not provide recourse because they cover gas quality but fail to quantitatively cover gas cleanliness. A common gas contract clause will state that the gas particulate contamination must be at a level at which no downstream equipment or process will be harmed. Once the GT is down and the damage has occurred, however, there is little an operator can do to prove the fuel used was off spec.
Fortunately, a real-time natural gas cleanliness monitoring and web-based alarm system that offers valuable protection for natural gas–fired power plants is now available. The ability to monitor pipeline cleanliness helps GT operators correct contaminant issues before equipment damage can occur.
Contamination Sources
Processed, clean, tariff-quality natural gas should be ready for the combustor nozzle. All too commonly, however, it is not. It is still typical for liquid and solid contaminants to reach and damage gas turbines. Experience suggests that pipeline contaminants invade point-of-use facilities for a number of reasons.
Hydrocarbon Dew Point. The hydrocarbon dew point of a gas stream is the point at which the temperature and pressure of the system are right for certain components of the natural gas to condense out of the gas in the form of liquid droplets. Standard fuel gas conditioning design suggests that the gas stream be superheated to at least 50F over the hydrocarbon dew point and/or moisture dew point, whichever is higher. The superheat temperature is usually set substantially higher than the operating temperature to help cover the effects of atmospheric temperature drops and pipeline fitting pressure losses that result in temperature losses.
Atmospheric temperature drops and pipeline fitting pressure losses can produce natural gas liquid condensate in the last few feet of the fuel gas piping between the fuel gas conditioning skid and the combustor nozzles. Cool morning atmospheric temperatures can reduce the skin temperature of the fuel gas conditioning skid equipment to the point where natural gas liquids can nucleate out of solution onto the walls of fuel gas piping and sometimes even the walls of the gas coalescer filters that are in place to remove such liquids.
Pipe fitting temperature losses are usually realized via a Joule-Thomson effect caused by a pressure reduction or control valve. The Joule-Thomson effect is an isoenthalpic expansion of natural gas that results in a temperature loss. If the temperature loss drops the gas temperature to the dew point temperature or lower, liquids will condense out of the gas stream, creating a new contaminant that GT operators have to deal with.
Compressor Lube Oil Carryover. Frequently, fuel gas booster compressors are included on-site to keep fuel gas streams at the specified operating pressure. Compressors are a consistent contributor of lube oil contamination to fuel gas pipelines. Reciprocating compressor lube oil losses have been measured up to 7 gallons per day per compressor. The lube oil aerosol carryover is normally removed with a filtration vessel called a filter coalescer. Failures normally occur when the filter coalescer is overwhelmed with more liquid contaminant than it can handle.
Rotary or screw type compressors are also sometimes used to give a final boost to fuel gas pressure. Rotary compressors utilize lube oil to cool the compression screw and to seal rotating components during the compression process. In order to perform rotary compression, lube oil is discharged with the compressed gas. A large coalescer, which is called a gas oil separator, is used to separate lube oil from the gas stream.
In addition, rotary compressor gas oil separation is extremely difficult, as the lube oil reaches temperatures as high as 220F, which greatly lowers its surface tension and viscosity. The other component that makes separation difficult is the volume of liquid present that must be separated. Rotary compressors have lube oil circulation rates between 10 and 150 gallons per minute. These volumes provide a massive opportunity for lube oil carryover. In fact, rotary compressor gas oil separators are notorious for allowing extreme amounts of lube oil carryover.
Poorly Designed Filtration Systems. Filter coalescers are normally designed with two stages. The first stage collects the liquid film or free liquids that travel on the pipe wall, usually by gravimetric means. The second stage utilizes a number of coalescer elements designed to remove solid and aerosol particles from the gas stream.
A target specification for liquid removal for a GT fuel gas filter coalescer is 10 ppb by weight. Well-designed coalescers can easily meet this requirement. Poorly designed coalescers will struggle to produce an effluent this clean. Filter coalescer performance issues usually originate from problems with the vessel or housing design.
- Common filter coalescer vessel design mistakes include the following:
- Skimping on the first-stage free liquid knockout area.
- Placing the coalescer elements too close to one another.
- Locating the outlet nozzle in an area that causes the gas to channel and not fully and equally utilize all of the available coalescing media.
The coalescer elements also play an important role in removal performance. GT operators need to heed the following warning: Not all coalescer elements are the same. Most elements can meet the target removal requirement. Elements differ, however, in their liquid handling capacity. Some coalescer elements are available that will handle 5,000 ppm by weight inlet liquid contaminant, while others will handle as low as 5 ppm. Fuel gas conditioning filter failures are a common source of combustor nozzle contamination.
All of these issues routinely result in new contaminant challenges for point-of-use fuel gas conditioning systems. If the contaminant loading is more than the system can handle, or if the dew point requires more heat duty than the heater can deliver, contaminants will make it to the combustor nozzles.
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