American Oil and Gas Reporter - September 2021 - 64

SpecialReport: Gas Gathering
Shale gas wells often are equipped
with packaged heater-separator units
called gas production units (GPUs). As
shown in Figure 1, a GPU consists of an
indirect glycol/water bath choke heater
and a separator. The heater section heats
the well stream to prevent freezing when
high-pressure fluids are expanded across
the pressure letdown choke and also reheats
lower-pressure fluids to the desired
separation temperature conditions. Some
GPUs are two-stage units (high and low
pressure) to help with managing flash
gas liberated from hydrocarbon liquid
condensate as it is reduced in pressure to
storage tank conditions.
While there are pros and cons to each
approach, these two hydrocarbon liquids
handling options clearly have a large impact
on gathering system line sizing and
liquids handling.
Dehydration removes water vapor and
separators remove free water (condensed
water and formation water) from the gas
stream. Free water removal at the pad/well
site, combined with dehydration, will
result in a " water dry " GGS, which has
significant benefits for hydrate prevention
and corrosion/materials selection.
Corrosion Inhibition
Because flowlines/pipelines are the
primary components of any GGS, preventing
internal and external corrosion is
a priority with metal pipelines. External
corrosion protection is relatively straightforward.
The primary corrosive species
is oxygen in moist soil, and the main
protection measures are a good external
coating and cathodic protection.
Internal corrosion control is more complicated
and depends on several factors.
Dehydrated systems with no free water
FIGURE 1
Gas Well GPUs on Shale Well Pad
are usually free of internal corrosion, although
there can be exceptions if occasional
upsets introduce water into the GGS. For
wet (nondehydrated) systems, the main
internal corrosion mechanisms are related
to the presence of carbon dioxide, hydrogen
sulfide and oxygen (present individually
or in combination). Microbiologically induced
corrosion also can be an internal
corrosion issue.
While there are numerous factors that
impact the severity of internal corrosion,
the most common material/corrosion control
strategy employed for an onshore
GGS with metallic pipelines is carbon
steel combined with a corrosion inhibitor.
For mild- to moderate-corrosivity systems,
carbon steel pipe such as API 5LX 42-52
and a nitrogen-based film-forming inhibitor
represent the most common " system. "
Typical injection requirements for
GGS applications are 1-2 pints of inhibitor/MMcf.
The actual protection effectiveness
of the corrosion inhibitor depends
on a number of factors, including:
· Relative and absolute CO2 and H2S
concentrations;
· Temperature and pressure;
· Hydrocarbon liquid and water
flowrates/compositions;
· Flow pattern/phase velocity effects;
· Inhibitor availability;
· System cleanliness; and
· Pigging program.
Except for the most severe applications,
where a corrosion-resistant alloy of some
type should be used, a properly designed
and operated corrosion inhibitor program
can be very effective in mitigating internal
corrosion of carbon steel pipelines. The
primary requirement is to ensure that the
polar corrosion inhibitor molecules contact
and adhere to the inside pipe metal surface.
This can be especially difficult if there
are solids/deposits (including corrosion
products) in the system, or if the flow
regime prevents contact of the inhibitor
with the metal surface (stratified flow
with the inhibitor in the liquid and none
in the vapor phase to protect the upper
part of the pipe). This is particularly
problematic in downhill runs of pipe,
where the flow pattern is nearly always
stratified and fluids in the pipe are cooling.
This is a major contributor to so-called
top-of-line corrosion, and often requires
batch pigging treatments, with the corrosion
inhibitor between two pigs, to ensure
360-degree contact of the inside pipe
wall with the inhibitor.
Internal corrosion caused by oxygen
can be a major problem, but usually is
restricted to very low-pressure gathering
systems. Many mature gas fields have
low-pressure gathering systems (even
sub-atmospheric) and oxygen ingress can
cause continuous problems in both the
GGS and receiving gas plant. Many shale
gas fields have vapor recovery units on
their condensate tanks, which can inadvertently
pull in air and cause difficulties
with respect to the GGS oxygen specification
limits.
Nonmetallic Flowlines
There are several nonmetallic options
for GGS applications, including spoolable
composite pipe (SCP) and high-density
polyethylene (HDPE). However, HDPE is
suitable only for low pressure systems. To
a large degree, nonmetallics eliminate both
internal and external corrosion concerns.
SCP typically consists of an inner thermoplastic
liner (usually HDPE), one or
more reinforcing layers (glass/aramid fibers
or steel), and an outer protection layer
(HDPE). Design pressures are as high as
3,000 psig, depending on the product and
diameter. Design temperature limits of
140 degrees F are typical, although some
manufacturers offer products with higher
temperature ratings. Depending on pipe
diameter, 1,500-5,000 feet of pipe can be
accommodated on a single spool.
Compared with steel, SCP's primary
advantage is the potential for significantly
reduced life cycle cost. Savings are achieved
through lower installation costs related to
64 THE AMERICAN OIL & GAS REPORTER
American Oil and Gas Reporter - September 2021

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