American Oil and Gas Reporter - June 2019 - 78

SpecialReport: Artificial Lift Technology

Lift Equipment Gets Tougher, Smarter
By Colter Cookson
An artificial lift engineer must balance
the desire to maximize production rates
and ultimate recoveries with the need to
limit costs by extending equipment life
and slashing power consumption. It can
be difficult to preserve pumps and other
artificial lift systems in unconventional
plays, where initial production often is
laden with sand and undulating laterals
give slugs the perfect place to form.
Fortunately, technological advances
are providing artificial lift engineers with
tools to address today's challenges. These
range from high-pressure compressors
that eliminate the need for failure-prone
gas lift valves to sophisticated remote
monitoring platforms and controllers that
keep equipment operating at peak efficiency. Meanwhile, continuous sucker
rods give the venerable rod pump a ticket
to the curve, versatile rod rotators let
pumpers adjust spacing safely and quickly,
and compact stuffing boxes provide frac
hit protection without violating height
restrictions.
Because of their ability to deliver high
initial production rates, electric submersible pumps have become the default
method for handling unconventional wells'
initial production. When the initial ESP
fails or becomes too inefficient, it may
be replaced by a smaller ESP, and may

transition to rod or gas lift, observes Bill
Elmer, vice president of engineering for
Encline Artificial Lift.
"ESPs can handle high production
volumes, but even well-designed ones
may only last three-six months before
they need to be replaced at a cost of
$150,000-$200,000," Elmer comments.
"The pumps also require power that is
expensive and difficult to obtain in many
areas, including the Permian Basin."
In plays with high gas-to-oil ratios,
gas lift offers a compelling alternative to
ESPs, Elmer suggests. "Gas lift handles
sand and works well in extreme deviations,
so it is a great fit for unconventional
wells," he says. "However, in a traditional
gas lift system, friction between the production tubing and fluid may limit production to only 1,500 barrels of fluid a
day, far less than an ESP."
The solution is to produce up the
annulus between the tubing and casing.
"On a well that has 23⁄8-inch tubing and
51⁄2-inch casing, the annulus has 2.8
times the flow area as does one with
27⁄8-inch tubing that normally would be
used," Elmer points out. "With that
much flow area, gas lift spends so little
energy fighting friction that it can deliver
production rates exceeding 3,000 barrels
a day."
Once production rates fall to 500 bbl/d,
the operator switches to producing up

Using specially built compressors, producers can employ an emerging gas lift technique
that involves injecting high-pressure gas down the tubing and producing up the annulus
between the tubing and casing. According to Encline Artificial Lift, this high-pressure
gas lift can deliver initial production rates as good or better than an ESP. It also minimizes the potential for downhole equipment issues by reducing or eliminating the need
for gas lift valves.

78 THE AMERICAN OIL & GAS REPORTER

the tubing with conventional gas lift or
plunger-assisted gas lift, Elmer outlines.
High-Pressure Gas Lift
While it's possible to produce up the
annulus using gas lift valves, Elmer recommends an alternative called high-pressure gas lift. "HPGL can deliver initial
production rates even higher than an
ESP," he states. "It does that by using
compressors that are equipped with compression cylinders originally developed
to fuel compressed natural gas vehicles
to increase the injected gas's pressure
above the 1,000 psi normally used."
Initially, that pressure may be as high
as 4,000 psi at surface. According to
Elmer, that translates to 5,000 psi down
hole, enough to unload the well quickly
even if it contains nothing but sand and
saltwater.
As bottom-hole pressure declines, so
does the pressure of the injected gas.
Eventually, Elmer says, the HPGL compressor no longer is needed and can be
moved to another site.
HPGL also is called single-point gas
injection because it eliminates the need
for the downhole gas lift valves normally
used in sequence to unload the well,
Elmer mentions. "This is great for reliability," he says. "Because they see unprocessed gas that contains water vapor
alongside contaminants such as carbon
dioxide and possibly hydrogen sulfide,
the valves' bellows are prone to corrosion failures. Eventually, the valves
will no longer open and close as designed, causing problems that will decrease production."
HPGL often can eliminate the need
for packers as well, Elmer adds. "All the
operator has to do is run a string of openended tubing into the well," he emphasizes.
"With so little equipment down hole,
there is a good chance he will never have
to pull the well or bring out a fishing
crew."
In mid-April, Elmer estimated 14 operators had tried HPGL. All of them
began using it on other wells, and the
first operator to try it now has more
than 150 high-pressure compressors in
the field. Elmer points out that those
operators include SM Energy, which is
achieving initial production rates in West
Texas as high as 6,500-7,500 barrels of
fluid a day.

American Oil and Gas Reporter - June 2019

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