American Oil and Gas Reporter - August 2021 - 51

Heat And Insulated Pipe
High-H2S gas fields tend to use heat
for hydrate prevention instead of dehydration.
In this case, the gas will not be
dehydrated, but kept warm. Although not
a particularly common hydrate prevention
strategy, there are a few applications, including
low-rate/high-pressure gas wells
with relatively short transport distance to
a centralized processing facility, and highrate/high-pressure/high-H2S
wells.
In some cases, a choke/line heater is
required at the well site to deal with the
large JT expansion cooling effect experienced
by choked high-pressure wells, especially
during startup. This is a somewhat
different application than preventing hydrates
in the GGS, but there are some common
aspects to the equipment utilized.
Low-rate/high-pressure wells face the
most hydrate risk. In fact, it is possible
for these wells to " hydrate off " in the
tubing hundreds of feet below the surface.
These are typically high-pressure/lowdeliverability
wells that are being choked
to meet a gas sales contract nomination.
Flowing tubing pressures easily can be
1,500-2,000 psig or more.
Combined with low flowing temperature,
conditions in the upper part of the
tubing, the wellhead and the christmas
tree up to the choke are inside the hydrate
formation region. There are a couple
ways to deal with this: injecting methanol
down the tubing through a capillary string
or down the tubing-casing annulus in
wells without a packer, or installing a
bottom-hole choke to take the required
pressure drop down hole (warmer temperature),
rather than across the surface
choke (colder). While sound in theory,
experience shows this does not always
work in practice.
Figure 3 shows a wellsite choke heater
to warm gas from the wellhead to prevent
hydrate formation associated with the expansion
pressure drop. These split-coil
glycol-water bath heaters have a choke
between the high- and low-pressure coils.
The temperature of the gas out of the
low-pressure coil can be adjusted to improve
wellsite separation/measurement or
to heat the gas before entering the gathering
system as a hydrate prevention strategy.
Figure 4 shows flowing temperature
profiles for buried flowlines/pipelines for
an assumed set of conditions and operational
parameters. Gas flow through nonthermally
insulated pipe cools quickly,
especially at low flow rates. Although
expensive, thermally insulated pipe is a
sound alternative to installing multiple
line heaters along a pipeline to periodically
reheat the gas to remain above hydrate
formation temperature.
A sometimes unappreciated drawback
AUGUST 2021 51
with insulated pipe is that because the
pipeline operates warm and wet, it presents
significant corrosion risk for steel lines
even with no H2S and low CO2. In particular,
top-of-line CO2 corrosion can be
severe in downhill pipeline sections that
predominantly operate in stratified flow.
The author has personal experience with
this problem, which went undetected for
years before a pipeline rupture occurred.
High-H2S conventional gas field gathering
systems often utilize both wellsite
line heaters and insulated pipe to keep the
well stream above hydrate formation temperature
all the way to the gas plant. Needless
to say, materials selection and corrosion
control are major considerations.
Chemical Injection
Methanol injection is the primary
method of chemical hydrate inhibition in
onshore GGS. While typically the lowest
CAPEX hydrate prevention option, it has
an ongoing chemical consumption operating
cost. Ethylene glycol and lowdosage
hydrate inhibitors are also an option,
but because of cost and other factors,
typically are used more off shore.
Methanol is a thermodynamic inhibitor
that is soluble in water and depresses hyONE
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American Oil and Gas Reporter - August 2021

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