American Oil and Gas Reporter - January 2017 - 84

Production Technology

Production Technology Still Evolving
By Dan Holder
The oil and natural gas industry has
been remarkably successful at finding
hydrocarbons, growing total U.S. proved
reserves of both oil and gas by 70 percent
in recent years, thanks largely to unconventional reservoirs.
However, efficiently extracting hydrocarbons from ultralow-permeability rocks
is no small feat. And the challenges are
only intensified by the multiphase nature
of the production flows, characteristically
steep decline curves, low recovery rates,
and of course, tight economic margins.
Companies are working with each other,
bringing in university researchers, and
combining new technology and processes
to help them overcome those challenges.
Fred Morrow, vice president of engineering for Superod, cites a company's
Southeast New Mexico operation as one
vision of what is on the industry's horizon.
The operator is targeting formations with
horizontal segments drilled from 10,000foot vertical wells, managing the field
through one control room, with supervisory
control and data acquisition architecture
monitoring each well.
Morrow says the wells typically have
very high initial production rates that
may exceed 2,000 barrels a day, but
output falls off rapidly. As output declines,
the wells move from electric submersible
pumps to fiberglass sucker rods from Superod when production falls below 500
barrels a day.
"The key to this is not only the fiberglass, but operators are doing things with
variable speed drives downhole card monitoring that is controlled remotely from a
central office. As production continues
to fall, the pumping unit slows," Morrow
describes. "The operator tries to keep
pump fillage between 85 and 95 percent;
if it is above 95 percent, the motor speeds
up; below 85 percent, it slows. The unit
is adjusting itself constantly to maintain
the type of fillage that gives maximum
production without developing a fluid
pound that can cause downhole problems."
Even though conditions are improving,
the industry still is nowhere near where
it needs to be economically, assesses
Cleon Dunham, president, chief executive
84 THE AMERICAN OIL & GAS REPORTER

officer and secretary for the Artificial
Lift Research and Development Council
(ALRDC). "Companies are trying to get
the most they can out of existing production, and they are focusing on recovering
as much from their wells as they can.
The investment focus has shifted from
drilling to maximizing efforts on existing
wells and facilities. There is a big focus
on automation, which is a relatively inexpensive way to gain more benefits."
Many downhole technologies will continue to make oil and gas production possible, and Dunham predicts evolutionary,
not revolutionary, improvements over the
near term. He points to ESPs as one
evolving sector, where technology advances are expanding operational capabilities and reducing application costs.
"One usually thinks of ESPs being
used in high-rate wells to produce hundreds
of barrels of liquid a day. But they are
getting to the point where you can put in
an ESP to effectively produce fewer than
100 barrels," Dunham describes. "We
also are seeing smaller-diameter ESPs
that work in smaller wellbores. They
don't necessarily have to be 51⁄2- or 7inch wellbores anymore."
Developments in the sucker rod field
include continuous and fiberglass units,
hollow rods that allow operators to introduce chemical treatments directly into
the well, and operation techniques to
help avoid the effects of excess gas levels,
including gas interference, Dunham says.
In the gas lift area, he describes industry
targeting optimizing operations such as
methods to determine the optimal depth
to install injection equipment, and the
best chemical combinations to deal with
oil and condensate mixtures.
Deep Production
Morrow says operators typically put
high-IP horizontal Bone Spring wells on
gas lift or ESPs until initial rates drop to
400-500 bbl/d, at which point they are
moved to rod pumps. "They will be on
rod pumping for the next 10 years or
better, before they eventually decline to
maybe 75 barrels of oil and 75 barrels of
water a day," he says.
As wells decline and switch to secondary recovery, operators must consider
physical factors such as depth, temperature

and pressure in choosing their artificial
lift techniques. Morrow says combining
fiberglass sucker rods and beam pumps
are a good choice for Bone Spring wells.
For deep wells, the weight difference between a one-inch steel rod (2.9 pounds
per foot) and a one-inch fiberglass rod
(0.8 pounds/foot) is significant.
"In an oil well, the surface pumping
unit may be 10,000 or 12,000 feet from
the downhole pump," he describes. "That
pumping unit not only is lifting the load
at the pump, but also the weight of the
rods themselves. In a 10,000-foot well
with fiberglass rods, the pumping unit
has 10,000-15,000 fewer pounds of rod
weight that it doesn't have to lift every
stroke. The big thing is the weight reduction, which allows the operator to use
smaller equipment and less power to lift
a given amount of fluid."
Advances in fiberglass sucker rods
also mean less concern about corrosion
in wells with hydrogen sulfide and carbonic acid, Morrow notes. Fiberglass
rods installed 30 years ago still are working, he says, estimating that as many as
half of all rod failures are caused by corrosion.
Superod is working to expand the
temperature range for its products, Morrow
says, pointing out that current fiberglass
sucker roads can work in up to 200degree downhole environments, while
many fields, including those in South
Texas and the Bakken Shale, can see
temperatures top 275 degrees. While some
resins used in the fiberglass can handle
275-degree environments, Morrow says
the high temperatures compromise their
strength, lowering rod loads and thus oil
production.
SCADA advancements also promise
to change operational costs for operators,
Morrow says. Typically, lease operators
have to drive to every well on a regular
basis to monitor conditions and check
for problems. With remote instrumentation,
the well equipment sends its data to a
central location, and field workers can
be dispatched on a well-by-well basis to
handle incidents.
"It is a much more efficient way to
operate producing wells. Instead of having
workers drive around acquiring data manually and looking for problems, the auto-

American Oil and Gas Reporter - January 2017

Table of Contents for the Digital Edition of American Oil and Gas Reporter - January 2017