American Oil and Gas Reporter - June 2015 - 68

SpecialReport: Artificial Lift Technology
pens in single-phase liquid flow.
If there are multiple upward sections followed by downward
sections in a horizontal well, these high-pressure drops in the upward sections will accumulate and cause significant blockage to
the flow from the toe to the heel.
Well Geometry

Considering the multiphase flow behavior and pressure
gradient difference in the upward and downward sections, a "toeup" horizontal well profile (where the toe is higher than the heel)
is preferred. The downward inclination of the lateral from the toe
back toward the horizontal curve will allow liquids to drain to
the heel section by gravity. The artificial lift apparatus can be
installed in the vertical or deviated section above the heel section.
In cases where a horizontal well has to be drilled with
undulations, careful selection of wellbore diameter is important
to minimize pressure drops in the upward sections. As shown in
Figure 2B, if the casing diameter is larger than the optimum value,
the pressure gradient in the upward section will increase as the
diameter increases. This is caused by greater liquid holdup. This
effect is more prominent at higher inclinations angles. The
optimum casing diameter depends on the liquid flow rate,
GOR, and fluid properties.
The pressure drop difference in upward and downward
sections of a horizontal gas well is much more significant than
in a horizontal oil well. Figure 3A shows the pressure gradients
versus casing diameter at three inclination angles in a horizontal
gas well producing 2 million cubic feet of gas and 50 barrels of
liquid a day. Liquid loading in the upward section causes a much
higher pressure drop if the casing diameter is oversized. An
optimized casing diameter can effectively reduce the liquid holdup
and keep the pressure gradient low. Therefore, a casing
completion design tempered from the heel to the toe will be
beneficial, especially for undulating horizontal wells.
The right combination of casing diameter and production rate
is critical for minimizing the pressure gradient in the upward
sections of a horizontal well, especially for gas production. Figure

3B shows predicted pressure gradients versus gas production rate
in a 20-degree upward section for different casing diameters. The
liquid flow rate is 50 bbl/d.
It is evident that at a lower gas flow rate (less than 4 MMcf/d),
the pressure gradient in large-diameter casing is higher than in
smaller-diameter casing. The casing diameter designed for the
high initial production rate may soon become oversized because
of the rapid decline. A smaller-diameter tubing may be used, which
acts like a velocity string to increase the flow velocity to lift the
liquids in the upward sections. Or, a bundle of small (e.g., 0.25inch) diameter tubing may be inserted, which can reduce
slippage dramatically between gas and liquid.
Artificial Lift Selection

Because of the rapid production declines in horizontal wells,
the artificial lift system selected must be flexible enough to operate
over a wide range of production rates, or the system should be
easily resized or replaced. Gas lift is preferred, especially in wells
with relatively high GORs. Casinghead instability probably will
be more severe with horizontal well gas lift because of the
significant gas volume stored in the lateral section. The gas lift
valve should be installed above the heel section.
There are proposals to inject gas in the highly deviated
section, or even at the toe of the horizontal well, to sweep out the
liquids. However, gas lift is effective only when the well deviation
from vertical is not too high, since its working principle is gravity
reduction. Injecting gas deep into the lateral section will increase
the frictional pressure drop caused by high fluid velocity and
increased tubing length. Intermittent gas injection in the lateral
section to purge liquid also may result in flow back into the reservoir.
For oil production from a horizontal well, rod pump is a
preferable choice that can cover low to medium production rates.
First, the well can be regulated with a choke for a lower production
rate so that the decline rate is more moderate. Then, a rod pump
can be used to extend production from the well much longer.
Installing a rod pump in the lateral section of a horizontal well
is questionable, since the gravitational pressure drop in the lateral
FIGURE 3B
Pressure Gradients in Upward Section versus
Gas Production Rate for Different Casing Diameters
(psia=2,000, angle=20° upward, QW=50 bbl/d)

FIGURE 3A
Pressure Gradients in Upward Sections
Of a Horizontal Gas Well
(psia=2,000, QG=2 MMcf/d, QW=50 bbl/d)

4,000

5,000
10 deg
20 deg
30 deg

2 in
3 in
4 in

3,000
-dp/dl (Pa/m)

-dp/dl (Pa/m)

4,000

3,000

2,000

1,000

0
0

4
d (in)

68 THE AMERICAN OIL & GAS REPORTER

10
QG (MMcf/d)

American Oil and Gas Reporter - June 2015

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