American Oil and Gas Reporter - March 2022 - 54

With any flow through a pipe from
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reservoir to surface, there are three main
contributors to pressure drop: gravity,
friction and acceleration. Given the low
rates, acceleration is negligible in these
wells, leaving gravity and friction as the
main contributors to pressure loss. However,
the surface head pressure against
which the well must produce also can
add backpressure to the system. The
higher the head pressure, the larger the
critical rate necessary to overcome backpressure.
Lowering head pressure by only
10 psig can make a tremendous impact
on liquid-loaded, low-pressure gas wells.
Injecting gas into the well annulus
lightens the fluid gradient and minimizes
the gravity-related pressure loss in lifting
the fluid to surface with a plunger. Gas
injection directly reduces the pressure
drop by reducing fluid density. Compression
can reduce both head pressure and
the density of the wellbore fluids, lowering
wellhead production pressure at surface.
Adding a " T " to the compressor's discharge
line allows some of the gas to be
injected back into the well and the remainder
to go to sales.
XTO Energy Inc. has numerous Barnett
wells that benefit from compression to
flow liquids and gas at low costs. For
this compression application, cost is a
function of efficiency. With a right-sized
unit outfitted with the proper automation,
efficient on-site compression and injection
are achievable.
A choke on the injection line is required
to control the amount of gas injected
down hole. With an automated choke,
the choke body adjusts to maintain a certain
injection volume. In the absence of
an automated choke, automation must
originate upstream of the choke to control
injection. This is where a rotary screw
compressor equipped with advanced programmable
logic controls has succeeded
on XTO well sites. The PLC control system,
coupled with a modem, allows users
to virtually connect to a unit and remotely
control it from anywhere.
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54 THE AMERICAN OIL & GAS REPORTER
Rotary Screw Packages
XTO Energy equipped three horizontal
Barnett wells (wells A, B and C) with
the rotary screw compressor packages
and PLC panels. After that, it evaluated
these systems by comparing them with
the reciprocating compressors that previously
performed the same function.
One aspect of success is properly
sizing a compressor given the performance
conditions. In these wells, when suction
pressure dropped below 45-50 psig, it
hampered the existing reciprocating compression
that was injecting gas down
hole. In Well C, the rotary screw package
replaced a large recip that had struggled
to inject efficiently with suction pressure
below 45-50 psig. Insufficient head loading
can occur when suction pressure is too
low for a reciprocating compressor, causing
the unit to run rough and reducing time
to cylinder/packing failure.
In wells A and B, rotary screw units
replaced small-horsepower, two-stage reciprocating
units. The units lacked telemetry
or autostart and recycle, and offered
limited speed control, while also requiring
at least 50 psig suction pressure. Between
plunger cycles, the fluctuating suction
pressure impacted the ability to stay under
load while maintaining a high discharge
pressure. This, in turn, cut the volumes
at which these units could deliver.
Since failure can occur when reciprocating
compression is not efficiently
loaded, units tend to experience more
downtime. Subsequently, the well will
not obtain the injection needed to stay
unloaded during downtime events, thereby
increasing nonproductive time and cutting
revenue.
Other Barnett wells in the area were
studied for downtime impacts of compressor
injection for liquids unloading.
The study showed that low-pressure wells
must always have a consistent source of
lift gas to stay unloaded. When they do
not, it can impact profit margins.
Another factor common in the Barnett
occurs when multiple wells on a pad
communicate with one another in terms
of flow. If one well on a pad gets loaded,
it can have a cascading effect on the
pad's other wells. As a result, the lack
of compression run time gets magnified
across a pad's producing wells. Of course,
considerable amounts of field personnel
resources are absorbed when responding
to compressor downtime issues. It involves
not only compressor mechanics
to bring a unit back on line, but also
field personnel to evaluate the unloading
of the well and return it to a routine operating
sequence that harmonizes with
the plunger system.
Reducing Backpressure
Well A has been producing since November
2010. As of mid-October 2021,
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American Oil and Gas Reporter - March 2022

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