POWER June 2010 - 52

GAS TURBINES
Real-Time Monitoring of Natural
Gas Fuel Cleanliness
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.
By David Burns, PECOFacet/Scientific Process Solutions Inc., a Clarcor Company
I
n 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
52
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. Failwww.powermag.com
ures
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.
POWER | June 2010
http://www.powermag.com
POWER June 2010

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