American Oil and Gas Reporter - June 2016 - 69

SpecialReport: Artificial Lift Technology

ESP Design Improves Well Performance
By Jeffrey Bridges
and Leslie Reid
OKLAHOMA CITY-Gas handling is
a complex and challenging artificial lift
issue in many oil wells, but can be especially problematic in horizontal wells in
reservoirs with multiphase flow regimes.
This includes tight oil plays as well as
conventional geology such as the Mississippian Lime, where advanced drilling
and hydraulic fracturing technologies
have allowed operators to transform a
reservoir that has been the target of thousands of vertical wells into a horizontal
resource play.
While many oil wells can produce
with small gas quantities, gas slugging is
a particular challenge. It occurs when
gas enters the wellbore rapidly or is released rapidly from solution. At a minimum, gas slugs create rapid local density
fluctuations that cause liquids to be unloaded erratically. This sporadic production
regime makes pumps lose prime and
cycle on and off. Under these conditions,
the gas separators and tapered pumps
normally used to prevent gas locking are
rendered ineffective. In severe cases, gas
can enter with such force that it displaces
casing liquid far above the downhole
pump.
Producing horizontal wells comes with
an additional set of challenges. Most horizontal wells have undulating paths that
lead to water accumulating in the low
spots of the laterals and gas accumulating
in the high spots. These accumulations
predispose the well to "sluggy" production
cycles and intermittent flow patterns characterized by alternating gas/liquid flows
(liquid slugs followed by gas pockets).
Within the wellbore, the region containing a gas bubble moves over a thin
liquid layer at the bottom of the pipe.
The liquid slugs, which usually are aerated
with the dispersed gas phase, are accelerated rapidly by the gas flow. Gas slugs
can be large, and can create considerable
operational issues for electrical submersible pumps and other lift systems
designed for consistent liquids flow.
These challenges are exacerbated in
the horizontal Mississippian Lime play,
where oil and gas production vary significantly because of the evolution of the
reservoir. A typical production operating
scenario starts with high liquid rates while

handling some gas. Over a period of a
few months, liquid production rates fall
while gas production rates rise, making
reliable and steady downhole pump operations a struggle.
One gassy Mississippian Lime well
in Kansas was experiencing large amounts
of gas cycling, and had experienced multiple ESP shutdowns caused by excessive
temperatures and "no-load" situations.
After previous ESP installations had been
unsatisfactory, a field test was conducted
with three main objectives:
* Determine whether the run life and
production of an ESP system could be
increased on the gas-slugging well;
* Implement a downhole recirculation
system inside an artificial sump; and
* Monitor the economic impact of
installing the artificial sump ESP system
in the well.
The challenges to the ESP system for
this test included low liquid in-flow during
severe gas slugging, high gas-to-liquid
ratios (in excess of 800 cubic feet per
barrel), difficult pump startup conditions,
and thermal and mechanical damage to
motor lead extensions. Given these challenges, traditional gas separation and handling technology was ineffective. As an
alternative, the operator decided to install
a downhole recirculation system inside
an artificial sump to prevent potential
gas locking, circulate fluid to cool the
ESP motor, and enhance reservoir drawdown.
Conventional Solutions
Gas slugging can be an issue for just
about any pump in conventional vertical
oil wells. For sucker rod pumps that rely
on fixed-volume compression, gas can
cause low-pressure compression cycles
(loss of compression) that prevent lifting
the tubing fluid column, ultimately shortening pump life and reducing productivity.
For ESPs and pumps that rely on centrifugal force, gas lowers fluid density
and prevents the pump from generating
sufficient pressure to lift the fluid column
(gas locking). This instability also lowers
production and pump run life.
As a result, pumps traditionally have
been positioned in the rat hole below the
perforations to take advantage of natural
separation and to avoid ingesting free
gas into the pump. However, because
ESP motors generate heat and must be

cooled to prevent premature failure, it is
common to utilize a cooling jacket or
shroud to force production fluid past the
motor in an ESP installed in the rat hole.
Another, less common, method to accomplish forced cooling is to install a recirculation system to pass some fluid
below the motor using a thin conduit.
Extended-reach horizontal drilling has
led to the development of tangent sumps.
Similar in function to rat-hole sumps,
tangent sumps provide a gas-avoiding
abode for the pump.
Tangent sumps have been used successfully in gas well dewatering for at
least a decade, and more recently have
FIGURE 1
ASP System Design

Gas Produced
Through Annulus

Pump

Recirculation
System

Seal

Motor

Tubing
Clamp

JUNE 2016 69

American Oil and Gas Reporter - June 2016

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