American Oil and Gas Reporter - March 2021 - 71

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SpecialReport: Production Optimization
the produced gas up the hole. Therefore,
the well can produce gas from the reservoir
under the lowest possible downhole pressure, or even on vacuum.
Another benefit is illustrated in Figure
3, which describes the process between
the downhole gas compression and the
wellhead gas compression on a chart of
gas pressure along the depth. In highly
depleted wells, the wellhead compressor
experiences lower dynamic pressure at
the compressor intake because of the
pressure drop along the depth from the
bottom hole, creating much lower density
and higher volumetric flow that prevents
the wellhead compressor from working
efficiently. However, the downhole dynamic pressure at the compressor intake
is much higher, with the higher density
and higher mass flow subsurface compressor helping continue gas production
even in depleted wells.

higher gas flow rates and lower bottomhole flowing pressures, increased gas
stream velocity carries more liquids out
of the vertical and horizontal sections.
Figure 4 illustrates the pressure ratio
needed to achieve a superficial gas velocity
of 20 feet/second in a liquids-rich Marcellus Shale well. The red dotted line
represents a pressure ratio of 1.0 without
downhole gas compression. The green
dotted line represents the pressure ratio

of 1.5 with downhole gas compression,
where the discharge pressure at the outlet
is 1.5 times higher than the pressure at
the inlet. Based on the 20 feet/second superficial gas velocity criterion, the minimum gas flow rate required to successfully
remove liquids from the horizontal section
would be 1,200 Mcf/d and without downhole gas compression. With SCS, however,
the minimum flow rate for effectively
sweeping liquids would be reduced by

Unconventional Reservoirs
The benefits that can be achieved with
an SCS in conventional gas wells also
apply to liquids-rich unconventional gas
wells. In long horizontal sections, trajectories undulate in a series of shallow
peaks (filled with gas) and troughs (filled
with liquids) that can lead to erratic and
intermittent production, sluggy and turbulent flow behavior, increased liquid
holdup, reduced hydrocarbon production,
and premature well abandonment.
Moreover, in a multiphase reservoir
system, gas will travel faster than liquids,
and the holdup will increase over time.
At low flow rates, the in situ density of
the fluid mixture will approach the liquid
density because of the excessive slippage,
and the well will start to flow in an oscillating mode, often followed by severe
liquid slugging.
The liquid fallback promoted by liquid
loading exerts backpressure on the reservoir
and increases pressure losses near the
wellbore region by altering relative permeability and fracture morphology. Under
this condition, produced liquids accumulate
in the wellbore and further decrease gas
production and accelerate the time until
the well can no longer produce and needs
to be prematurely abandoned.
SCS technology provides a novel solution to the combined challenges of liquids in the horizontal wellbore and in the
formation. The increased reservoir drawdown by the subsurface compressor actively induces more mass flow rate from
the formation to the wellbore. With the
MARCH 2021 71

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