American Oil and Gas Reporter - March 2022 - 58

SpecialReport: Gas Well Unloading
January 2008. As of mid-October, production
was 96 Mcf of gas and 18 barrels
of water a day at 135 Mcf/d gas injection,
109 psig casing pressure, 55 psig tubing
pressure, and 61 psig line pressure (Figure
3). The bumper spring setting depth is
6,379 feet at 47 degrees deviation.
The 108-mm rotary screw compressor
was installed on June 30, 2021. Three
FIGURE 2
Well B Production Data
400.0
rotary screw unit set
350.0
300.0
250.0
200.0
150.0
100.0
50.0
0.0
1/24/2021
3/15/2021
Gas Production
FIGURE 3
Well C Production Data
180.0
160.0
140.0
120.0
100.0
80.0
60.0
40.0
20.0
0.0
4/24/2021 5/14/2021 6/3/2021 6/23/2021
Gas Production
7/13/2021
Water Production
Gas Injection
58 THE AMERICAN OIL & GAS REPORTER
8/2/2021
8/22/2021 9/11/2021
Tubing Pressure Casing Pressure
10/1/2021 10/21/2021
Line Pressure
rotary screw unit set
5/4/2021
Water Production
Gas Injection
6/23/2021
8/12/2021
10/1/2021
Tubing Pressure Casing Pressure Line Pressure
months prior to compressor change out,
the smaller reciprocating compressors were
shutting down because of low suction
pressure conditions. The recips averaged
71 Mcf/d gas production at 155 Mcf/d gas
injection and 110 psig casing pressure.
Through mid-October, the well averaged
89 Mcf/d gas production (up
25%), gas injection averaged 143 Mcf/d
(down 8%), and casing pressure averaged
104 psig (down 6%) on the rotary screw
compressor. A constant 20 psig suction
pressure was maintained with a 62 psig
line pressure. The last three months on
the production graph show consistent
daily gas production, steady injection
volumes and constant casing pressure.
The injection rate appears to be optimized,
and most importantly, indicates
no downtime.
Increased Run Times
Keeping mature, low-reservoir pressure
horizontal shale gas wells unloaded
can be a challenge. Achieving success
takes the right type of artificial lift solution
tailored to the well's individual
needs. When looking at shale wells
with low pressure and volumes below
critical rates, one needs to attempt to
lower the head pressure back against
the well while ensuring the compressor
can run consistently.
Each of the three Barnett wells exhibited
marked increases when compressors
were changed from reciprocating units
to rotary screw packages that could deliver
GAPL injection while also lowering critical
wellhead backpressure by 10-30 psig.
Only rotary screw compressor packages
are able to get the wellhead suction pressure
down to a range around 20 psig,
which seems to be vital in getting these
wells to unload. Proper compressor maintenance,
as well as real-time telemetry
alarm and control, are critical to achieving
ideal run time.
The PLC-based advanced control system
allows XTO to remotely control rpm
(injection rate). As pressure depletes on
older leases, XTO only injects intermittently
instead of continuously while lifting
the plunger. When the plunger goes into
after-flow or off-time, the controller shuts
off injection. As an alternative on wells
with no controller, casinghead pressure
transducers are used to control when an
injection valve opens and closes. These
advanced controls provide a huge advantage
over the previous compressors used
on the three wells, which lacked PLCs
with auto-start and remote control access
to change compressor settings.
Well A has had only 27 hours of fault
downtime since it was set in February
American Oil and Gas Reporter - March 2022

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