American Oil and Gas Reporter - June 2015 - 66

SpecialReport: Artificial Lift Technology
FIGURE 1
Multiphase Flow in Undulated Horizontal Well

In order to apply artificial lift cost effectively and to maximize
estimated ultimate recoveries from horizontal wells, the artificial
lift methods selected must be flexible to cover the significant and
rapid changes in flow rate over a well's life cycle. For this reason, different types of artificial lift often are implemented in the
same well at different points in the production process. In fact,
it is common for horizontal wells to use two or more forms of
lift within only a few months of starting production.
In addition, with the majority of horizontal wells in resource
plays producing both liquids and gas, the trajectory of the lateral and the completion design must be planned based on multiphase flow behavior. The multiphase hydrodynamics in horizontal wells change dramatically with variations in inclination, behaving very differently from vertical wells.
Specific issues related to artificial lift need to be analyzed carefully in horizontal wells in unconventional reservoirs. These include installation location, gas/liquids separation, eliminating slugs,
and managing flow rate.
Major Challenge

Slugging can be a major challenge to the performance of rod
pump and electric submersible pump systems. The alternating arrival of a liquid slug and a gas pocket make separation difficult
and cause significant gas entrainment, which can deteriorate pump
performance. This problem is exacerbated in highly deviated and
horizontal wells, where slug- and gas-pocket lengths tend to be
FIGURE 2A

much longer. In fact, in a near-horizontal gas/liquid pipe flow,
slug length is about two times the slug length in a near-vertical
pipe flow.
The asymmetric liquid film distribution is postulated to require
a longer distance for the velocity profile to develop in the slug
body. Corresponding to the same liquid flow rate and gas-to-oil
ratio, the liquid film region also becomes longer and slug frequency becomes lower. Terrain slugging and flow instabilities may
occur as a result of the significant gas volume and valley profile
of the horizontal well at relatively low production rates.
There are distributed inflows through the multistage perforations in a horizontal well. The flow rate along a horizontal well
gradually increases from toe to heel. Other than that, the multiphase flow behavior in horizontal wells is similar to that in hillyterrain pipelines. Advances in mechanistic modeling of multiphase
flow at different inclinations can help elucidate the multiphase
hydrodynamics of horizontal wells.
Figure 1 shows typical multiphase flow behavior in an undulating horizontal well. In the downward flow sections, the gas/liquid flows are stratified normally. In the upward sections, at lowto medium-fluid velocities, slug flow is the common flow pattern because of liquid accumulation caused by gravity.
A unified model has been developed through a cooperative
industry/academic research consortium at the University of Tulsa for three-phase (gas, oil and water) flow in wells, flowlines
and pipelines. The model can be implemented in commercial simulators to calculate the multiphase flow hydrodynamic behavior
in horizontal wells.
Figure 2A shows predicted pressure gradients versus casing
diameter in upward and downward 10-degree sections of a horizontal well at 2,000 psia. The liquid production (Qo) is 2,000
bbl/d and GOR is 1,000.
When the casing diameter is relatively large, there is a significant gravitational pressure drop in the upward section as a result of high liquid holdup. However, this gravitational pressure
drop will not recover in the downward section, where the liquid
holdup is very small. This is radically different from what hapFIGURE 2B
Pressure Gradients in Upward Sections
Of a Horizontal Oil Well
(psia=2,000, QO=2,000 bbl/d, GOR=1,000)

Pressure Gradients in Upward
And Downward Sections of a Horizontal Well
(psia=2,000, QO=2,000 bbl/d, GOR=1,000)
3,000

4,000
10 deg
-10 deg

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

-dp/dl (Pa/m)

2,000

10 deg
20 deg
30 deg

1,000

2,000

1,000

-1,000

0
0

6
d (in)

66 THE AMERICAN OIL & GAS REPORTER

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d (in)

American Oil and Gas Reporter - June 2015

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