American Oil and Gas Reporter - June 2018 - 105

liquid so it is easier to lift. Ellithorp says
this increases production and reduces the
flowing bottom-hole pressure, allowing
the pump to stay above the curve longer.
"With the first-generation tailpipe system, we hit home runs a third of the time
and doubles a third of the time," he
relates. "However, in some of the wells,
the system seemed to have no effect.
After 160 runs, we had enough data to
identify the original design's limitations
and develop solutions."
The second-generation design features
an integrated anchor and isolation system
that is more robust and easier to run, Ellithorp says. "We had the opportunity to
test this system with several large operators, including ones in the Permian," he
comments. "During those tests, we installed temperature and pressure gauges
at both ends of the tail pipe, the base of
the tool set, and the pump's discharge.
The gauges confirmed the isolation's reliability, but also revealed an inaccuracy
in the correlations generally used for
flow velocities in horizontal wells.
Those correlations do not accurately
account for the effect inclination has on
how fluids and gases separate as they
travel through the curve, Ellithorp details.
"By using more accurate correlations,
we have implemented a series of upgrades
that should feed fluids and gases more
efficiently through the curve," he reports.
The design improvements have paid
off, states Ellithorp, noting that the
tailpipe system can be used in a much
wider variety of applications. As an example, he cites installations in Cleveland
Wash wells that are around seven years
old. "One of the wells had a 90-day average production of 10 barrels of oil
and 37 Mcf of gas a day before the installation. In the 70 days after installation,
oil production doubled to a sustained
rate of 20 bbl/d and gas production
steadily climbed to reach 150 Mcf/d,"
he says.
The tailpipe-and-separator concept excels in new wells, Ellithorp adds. "In
ESP wells, our system has handled 2
MMcf/d-3 MMcf/d rates even with GLRs
exceeding 3,000-to-1," he says. "With
rod pumped wells, we have done more
than 600 barrels of fluid a day."
While he generally advises against
trying the system in toe-down wells with
a steep inclination, Ellithorp says it has
had solid and repeated success in flat or
toe-up wells. "In a new well, we often
see 25 percent increases in production,
and in old wells, we often see increases
between 50 and 100 percent," he reports.
"The payback period can be as fast as
two weeks and generally tops out at three
or four months."

* Generation 2 Modiﬁed (G2M)
* 2018
* Lessons learned from gauge data
* Consistent ID's-CFD
* Toe Isolation
* More proprietary/patented

Echometer UPS is reﬁning systems that help rod and electric submersible pumps in horizontal wells run efficiently by using isolation to force gas and liquids through a tailpipe
that extends into the lateral. The company explains that the tailpipe's small diameter helps
the production stream reach critical velocity, making ﬂow more uniform and gasifying the
liquid so it is easier to lift. This increases pump ﬁll rates and production signiﬁcantly.

Frac Hit Protection
Because blowouts induced by completions put lives at risk and damage
equipment, operators generally shut down
and seal wells when frac jobs are being
performed close by. This has created a
need for high-pressure BOPs that are
easy to activate and reliable even after
multiple uses, says Denis Blaquiere, managing director of Oil Lift Technology
Inc., an Apergy company.
Toward that end, Blaquiere says Oil
Lift has developed an elastomer geared
for BOPs in unconventional plays. "We
needed to make sure the elastomer could
endure the oil and corrosion it encountered
during each use without degrading so
the operator could be confident it would
work several times," he says.
"We are happy with the elastomer's
performance in the field," Blaquiere reports. "The rubber's integrity stays consistent through the life of the well, so
whether it is day one or two years later,
it will provide a consistent seal around
the polished rod."
He adds that Oil Lift is developing a
hydraulic system that allows BOPs to be
activated remotely, eliminating the need
for someone to visit each pad ahead of a
frac job.
The pressure ratings of the BOPs depend on flange size, and range from 3,000
to 10,000 psi, Blaquiere continues. "For
operators that do not need a 5,000-10,000

psi system but want stronger protection
than the 1,500-psi BOP and flow T often
used on rod-pumped horizontal wells,
we have developed an economic 3,000psi system," he says. "This system combines the flow T and BOP seal with a
locking function into a compact package
at a comparable price to the 1,500-psi
BOP and flow T."
To offer the higher rating at that price,
Blaquiere says Oil Lift standardized components across wellhead configurations
and optimized its supply chain to source
components at a low cost. "Because the
system is integrated, it eliminates the
connection between the flow T and the
BOP, which reduces leak points. It also
cuts a few inches off the wellhead stack's
height, which should make it easier to
work around when spacing pumps or tapping bottom," he comments.
"The sealing system in the 3,000-psi
BOP is the same as the one used in our
10,000-psi units," he adds. "That provides
a level of reliability and allows the system
to be serviced and rebuilt rather than discarded, which should dramatically reduce
long-term costs."
All of the company's BOPs can lock
the polished rod in place to increase
safety during stuffing box changes and
other well servicing tasks, Blaquiere mentions. "By locking the polished rod in
place below the seal housing, a field hand
can change the seals without risking a
pressure breakthrough or movement that
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American Oil and Gas Reporter - June 2018

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