Hydrocarbon Processing - December 2021 - GP-27

TREATING & NGL
solved and total water. Free water is not dissolved in NGL. In some
cases, it is characterized as the bulk fraction of water that separates
out more easily by separators or by using coalescers. Emulsified
water is contained in small drops (typically 0.1 micron-50 microns)
and is usually more difficult to separate. Soluble water is
dissolved at the molecular level in the hydrocarbon phase.
Total water content in condensate downstream of the inlet
separators is typically present in concentrations varying from a
few hundred ppmw up to 5%. The salinity of the water contamination
is determined by the formation of the water, and also varies
significantly from a few hundred ppm up to a few hundred thousand
ppm.12
Quality specifications of the dehydrated condensate
prior to the stabilizer are project-dependent and typically show
free water concentrations ranging from 0 ppmv to < 100 ppmv.
Usually, free water is removed from the condensate by using
coalescer technology, or by cooling and passing it through
a high-pressure separator. Complete free water removal from
condensate is often difficult due to the formation of stable condensate/water
emulsions, caused by the presence of surfactants,
such as hydrate inhibitors and corrosion inhibitors that lower
the interfacial tension.3
Also, the condensate contains water in
the soluble form. The solubility of water in the condensate is dependent
on the fluid temperature and on the composition of the
condensate; as a consequence, it can range between 50 ppmw
and 650 ppmw, typically.
When moist NGL becomes cool, it can freeze and block
NGL lines or pipes. Moreover, the presence of dissolved water
in NGL beyond its solubility level is not advisable for transport
on pipelines, because any change in ambient temperature or
line pressure can lead to the development of free water from dissolved
water. The free water can easily combine with acid gases,
which can lead to corrosion issues in the condensate storage
tank and in the export pipeline. Corrosion of the export pipeline
may also represent a major integrity issue that could lead to
premature replacement of some sections of the pipeline, if left
unattended. An accurate prediction of free water formation is
essential to prevent such problems.
The solubility of water in hydrocarbons, even at ambient
temperatures, can have great practical importance.14
Based on
empirical and theoretical considerations, formulations are available
in the literature for the prediction of water solubility in hydrocarbons
and its dependence on temperature.14-21
Results. Samples from six gas handing facilities were subjected
to gas chromatography analysis. The composition (in vol%)
The experimental
method is the more accurate way of determining water
content at varying process temperatures. In this study, solubility
of water in NGL at varying process temperatures was measured
by using the NGL composition and the saturation vapor pressure
of the pure components present within it. The obtained
values were confirmed with Karl Fischer titration. The resulting
solubility curve can be used for predicting free water formation
at NGL handling facilities.
Outline of experimental procedure. The NGL used in this
study were taken from the export pipelines of five different gas
handling and processing facilities in Saudi Arabia.
NGL composition. NGL composition was measured using
a gas chromatograph equipped with a thermal conductivity detector
(TCD), as well as an open tabular column of 100 m × 0.25
mm inside diameter, fused silica-coated with 0.5-micron-bonded
methyl silicon. A helium carrier gas linear flow was estabFIG.
2. Setup for NGL sample preparation for KFT.
Gas Processing & LNG | NOVEMBER/DECEMBER 2021 27
lished at 30 ml/min. Injector and TCD detector temperatures
were maintained at 220°C and 250°C, respectively. The column
oven temperature was programmed for an initial temperature of
70°C held for 4 min, a ramp-up to 8°C/min, and a final temperature
of 200°C for 16 min. The injection volume was 1 µL.
Total water content. The water content of samples from
each location was subjected to Karl Fischer coulometric titration
(KFT) by following ASTM E1064-16.13
With this method,
dissolved and free water can be measured together. The condensate
sample was collected in a dry, high-pressure, coated
stainless-steel bomb. In the laboratory, the initial weight of the
sample was recorded, and the condensate sample was scrubbed
through dry ethylene glycol (25 ml in a separatory funnel).
At first, the high-pressure gas associated with the condensate
was allowed to bleed slowly through the solvent. When the
pressure had dropped considerably, the bomb was inverted and
the remaining liquid condensate percolated through the glycol.
When the bomb was empty, a gas line was attached to the upstream
valve, and dry argon gas was purged through the bomb
while heating the bomb walls with an electrical hot air gun. This
procedure ensured that residual moisture on the internal walls
of the bomb was transferred to the glycol solution (FIG. 2). Two
distinct solvent layers should form: a lower glycol layer and an
upper condensable hydrocarbon layer. The glycol layer is run
off for Karl Fischer (KF) coulometric analysis.
Determination of water saturation constant. To confirm
the calculated water saturation constant (Cs), the result was
checked with KF results. For this purpose, a sample from GPP3
was used to prepare a water-saturated hydrocarbon sample
(excess water observable) mixed continuously at 300 rpm with
magnetic stirrer. Then, the sample and stirrer were placed in a
chamber at a set temperature and given enough time to reach
equilibrium (18 hr). A coulometric KF titration cell was prepared
and set for conditioning. The accuracy of KFT was verified
by checking the solution injections. The mass of 1 ml volume
at set temperature (23°C) was measured and transferred to
the KF chamber. TABLE 5 shows the measured saturated moisture
concentration by KFT.
Hydrocarbon Processing - December 2021

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