American Oil and Gas Reporter - June 2016 - 73

SpecialReport: Artificial Lift Technology
life and increased production. Other benefits included fewer man-hours spent optimizing a dynamic operation, continuous
motor cooling, and motor lead extension
protection through high dogleg severity.
There also were potential disadvantages
that had to be considered. Most importantly, perhaps, was additional system
cost that had to be recovered through increased production. Other disadvantages
were navigating additional downhole
hardware and a raised equivalent pump
intake position, which could lead to lost
production.
In addition, it was recognized that the
recirculation system could lead to increased
sensitivity to solids trapped in the bottom
of the can. If the recirculation conduit
became plugged, the motor cooling method
would cease to function properly and the
pump would overheat.
Table 1 shows the size of the ESP
equipment and its location in the wellbore.
A straight-tangent section was available
in the curve, allowing the ESP to be
landed at a lower depth, compared with
the vertical section. The primary benefit
to setting in the tangent was that the effective intake of the system with the
shroud above the pump would not lose
as much true vertical depth. The change
in depth enabled greater drawdown and
more production.
While installing extra equipment did
mean a slightly longer installation time,
the beneficial impact of using the ASP
system was evident immediately on startup.
Startups for the previous ESP strings
were difficult, likely as a result of gas

TABLe 1
Artiﬁcial sump Pump installation design
eQUiPMeNT
Motor
4½-inch Od, 108 HP
Pump
4½-inch Od, 284-stage tapered
LOCATiON iN WeLL
Pump intake
5,072 feet Md @ 53º (4,965 feet TVd)
Bottom of AsP 5,113 feet Md @ 53º (4,984 feet TVd)
Top of AsP
4,913 feet Md @ 43º (4,862 feet TVd)

not achieve the level of oil production
possible with an ESP. Consequently, a
second ESP system with tapered pumps
with gas handling stages and a gas separator was installed to optimize production
volumes.
Production was returned to previous
levels, but the system ran for only three
months before another electrical failure
occurred. Figure 2 shows the well's production history using the different artificial
lift methods.
The well could not financially support
installing a new ESP system every few
months. In fact, the economics dictated
that an ESP run reliably for a minimum
of six months to achieve an acceptable
return on investment. With experience in
drilled sumps showing a valuable reduction
in NPT and improved reliability, the decision was made to install an ESP in the
artificial sump.
When looking at the expectations of
the ASP system design, the advantage
and disadvantages were considered. Gas
avoidance and gas slug management were
the top priorities that would lead to other
benefits with the change in system design.
With increased stability, there would be
fewer shutdowns, leading to longer run
figUre 3

Production History after installing AsP system
10,000

1,000

100

Oil (bbl/d)

Water (bbl/d)

Gas (Mcf/d)

01
3
Ap
r-2
3-

01
3
ar
-2
M

-2
Fe
b
3-

01
3

01
3
-2
Ja
n
3-

ec
-2

01
2

01
2
ov
-2
N
3-

01
2
3-

-2

-2
Se
p
3-

Au
g

-2

01
2

ingress while the pump was working to
lift liquids to the surface. With the artificial
sump system, the ESP was primed with
several hundred feet of liquid, preventing
gas interruption.
Figure 3 shows the production history
for the first eight months after installing
the ASP. Peak production levels were
maintained and NPT was almost completely eliminated, dropping to only 2.6
percent (the majority of which was
weather-related field power issues). Instead of struggling to keep the ESP system running, the well became virtually
problem free and was carried to near
terminal decline. In addition, the effective
fluid level was consistent at the system
intake, and resulted in maximized system
inflow.
The artificial sump system dramatically
improved "end-of-life" economics in the
Mississippian Lime well, and the results
are now being replicated on other plays
with similar success.
r
Jeffrey Bridges is a technical
manager for the Mississippian Lime
play at Baker Hughes. He is responsible
for designing and developing artificial
lift systems for applications in the
play, and supports designing and developing applications in other U.S.
areas. Throughout his 10 years in the
industry, Bridges has held positions
in global support applications, project
engineering, remote monitoring performance, and engineering optimization. He has expertise in many facets
of ESP systems, including in unconventional plays, alternative deployment,
and remote monitoring. Bridges has
three patents and holds a B.S in mechanical engineering from Oklahoma
State University.
LesLie reid is a technical subject
matter expert for the linear electromagnetic-actuated pump (LEAP)
adaptive production system at Baker
Hughes. He has held several artificial
lift roles, including product engineer,
regional engineer, and artificial lift
adviser for Baker Hughes' North
American operations, specializing in
the unconventional market. Prior to
joining Baker Hughes, Reid spent five
years with Halliburton. He has nine
patents and holds a B.S. in mechanical
engineering from Oklahoma State
University.
JUNE 2016 73

American Oil and Gas Reporter - June 2016

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