Hydrocarbon Processing - May 2021 - 70

Process Controls, Instrumentation and Automation
corrosion can cause enormous damage.
As a given volume of gas makes its way
from a source to its consumption point,
it may experience variations in temperature, above and below the immediate dew
point, causing water to change phase multiple times. If enough vapor condenses in
a cold section of pipe, liquid water can accumulate in a low spot. If the temperature
is cold enough, water accumulations can
freeze, causing solid clogs. Even if the water remains a liquid, it may cause enough
of a blockage to force the gas velocity to
increase, entraining water droplets in the
gas stream or pushing liquid slugs that accumulate somewhere else downstream. If
a slug reaches the final use point (e.g., gas
turbine), it can cause serious damage.
Water can be removed by chemical and
physical mechanisms, but this adds processing costs. Consequently, there is little
incentive to treat gas once it meets the
standard for tariff gas. This amount varies
between 50 ppmv-200 ppmv, depending
on the location. Once water is below the
limit, it is less of a problem-provided it
stays there and continues to flow from a
reliable source. The supply can and will
change at various times, so there is no reason to assume that conditions at one time
or location will invariably persist. Given
all these considerations, knowing the specific moisture content of the gas flow in
real time is critical.
Measuring water content. A small

selection of measurement technologies

can determine the amount of water in a
natural gas pipeline, and, as is normally
the case with instrumentation, each has
its combination of practicality, accuracy
and cost trade-offs. All typically involve
extracting a sample for individual testing,
rather than inserting a sensor for a continuous real-time reading. The following
are several common electrochemical and
electromechanical approaches:
* Aluminum oxide: Water content
is determined by measuring the
change of capacitance of water
molecules captured in microscopic
pores across the sensor surface. After
an increase in water content, the
pores must be dried. Problems occur
when molecules are trapped inside,
as this causes incomplete drying,
or when surface contamination
clogs pores, keeping molecules out.
This technique can also misidentify
glycol and methanol content as
water. These characteristics make
these types of instruments prone
to drifting and, therefore, to being
maintenance intensive.
* Phosphorus pentoxide: Gas
passes through a cell containing
electrodes coated with phosphorus
pentoxide able to electrolyze water
molecules. Current passing through
the electrodes is proportional
to the amount of water present.
Combining the gas flowrate with
the consumed current yields
an absolute moisture content

FIG. 2. When water mixes with other contaminants in natural gas, corrosive acids can form
that can attack carbon-steel piping from the inside.

70 MAY 2021 | HydrocarbonProcessing.com

measurement. However, the reading
can be distorted by changes in
flowrate through the analyzer or
methanol content in the gas, which
is read as water. The sensor is also
susceptible to contamination like
aluminum oxide and must be
replaced on a regular basis, thus
increasing operational costs.
* Quartz crystal microbalance:
Sample gas is fed into a chamber
where water molecules condense on
a chilled surface attached to a quartz
crystal. The action assesses the
change in mass of the microscopic
amount of liquid that forms. This
approach has high sensitivity, but it
cannot differentiate between water
and other liquids that condense,
such as glycol. If the mechanism
does not fully dry between samples,
then readings will appear higher
than actual. Corrosion inside the
chamber is common when H2S and
CO2 are present in the sample.
* Chilled mirror: This approach
calculates water content by
determining the dew point. A glass
surface inside the sample chamber is
chilled until the dew point is reached
where condensation forms, which
can be detected optically or by visual
inspection. Again, this technique
lacks the ability to identify water
specifically apart from other liquids
that may be in the stream.
A common drawback to these approaches is the potential for contamination (TABLE 1). Some contaminants-such
as compressor oil, methanol and amine-
can cause slow or inaccurate readings.
Other contaminants can poison the sensor and require replacement. For example,
chlorine and ammonia traces in enough
quantities can damage all these technologies, except for phosphorus pentoxide.
The problem, ultimately resulting
from a poorly performing electrochemical sensor, is a mistrust of the technology. Operators simply assume that the
reading is incorrect, and act on whatever
estimate they substitute for reliable data.
This leaves two possibilities. First, they
assume that the gas cannot possibly have
as much water as the sensors indicate, so
they take less action than is truly merited,
thus allowing the corrosive conditions to
get worse. Second, they assume that the
gas must have more water than the sensors

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