American Oil and Gas Reporter - June 2019 - 68

SpecialReport: Artificial Lift Technology
TABLE 1
Examples of Increased Submergence of Downhole Pumps with Multiphase Pumps
Well/Artificial Lift Method
CP-1464
Sucker Rod Pump
CP-1461
ESP

Pwh Before
(kgf/cm2)

Pwh After
(kgf/cm2)

Pcasing Before
(kgf/cm2)

Pcasing After
(kgf/cm2)

11
5
9.4
4.4
Improvements enabled by increased downhole pump submergence

Sub Before
(m)

Sub After
(m)

130

265

20
8
9.3
4
0
Improvements enabled by 10 percent reduced motor current and increased ESP submergence

Source: 2018 Multiphase Pump Users Roundtable South America

push to accelerate recovery from shale and tight formations
with faster decline rates. In North America, more than 85% of
all producing wells are on some form of artificial lift. In
addition, multiwell drill centers and pad production are used to
maximize operating efficiencies, centralize surface processing
and minimize facility footprints.
For all its benefits, pad-based unconventional reservoir development also can lead to complex well architectures with
long horizontal legs. The added complexity makes lifting with
conventional downhole pumps difficult and can present the
operator with a whole new set of problems, including unpredictable
production flows with declining revenue streams because of interruptions and unplanned costs for well service, workovers
and well interventions.
To overcome this challenging production environment, operators are adding multiphase boosting with twin-screw pumps
to existing artificial lift systems. Installing a multiphase pump
on a multiwell gathering system offers many advantages for
optimizing artificial lift. Reducing the flowing surface pressure
reduces backpressure on flowlines, production headers, wellheads, and further upstream, downhole pumps. The lower
surface pressure results in lower bottom-hole pressure for improved IPR, better well inflow and increased liquid levels in
the wellbore.
Higher liquid levels are important for artificial lift. The
deeper submergence of ESPs and sucker rod pumps enhances
hydraulic performance by improving net positive suction head.
At low wellbore liquid levels, downhole pumps operate in or
close to the bubble point region. Gas will come out of solution
and restrict the inlet flow, resulting in poor hydraulic performance
with an instant production drop and possible damage to the
equipment.
By reducing flowing wellhead backpressure with a multiphase
pump, the resulting higher liquid level will keep the gas in
solution and allow the downhole pump to operate above the
bubble point. A downhole pump running at its optimal efficiency
point on the curve will improve its gas handling ability and substantially reduce the risk of vapor locking and head loss caused
by entrained or free gas.
As shown in Table 1, after a multiphase pump was installed
in one field application, the higher liquid level associated with
68 THE AMERICAN OIL & GAS REPORTER

the lower bottom-hole pressure added significant submergence
of both ESPs and sucker rod pumps. The reduced hydraulic
work improves service life, reduces electric loads on ESPs, and
lessens wear and tear on beam pump rods, couplings and connectors.
An additional advantage manifested itself in a situation
where there were problems maintaining constant production
flow and pressure in test lines from wells during testing. Placing
a multiphase pump down stream of the test separator facilitates
well testing by managing test line flow using the pump's speed
control. The flow is directly proportional to speed and largely
independent of backpressure from the production separator.
Wells on gas lift also can improve production and total
recovery substantially when multiphase pumps are used to
reduce backpressure. Gas-lifted wells, which have a tendency
to liquid load and can experience very unstable flow because of
lift gas supply or underperforming gas lift valves, will be
supported by the reduced backpressure created by a multiphase
pump. In wet-gas wells, the reduced wellhead backpressure
will assist in unclogging the liquids trapped in the wellbore
much faster than is possible with conventional plungers, quickly
bringing wells back to production.
Additional Benefits
Multiphase pump-assisted downhole pumps will perform
more efficiently when facing flow assurance challenges that
relate to handling viscous oil, oil/water emulsions, and high
gas-to-oil ratios. Unpredicted events in a producing formation
can result in gas pockets or gas breakthrough can start to
develop. Equally possible are flow assurance issues in wells
subject to EOR production when emulsions occur with variations
in water cut.
Any of these conditions present difficult operating challenges
for any type of downhole pump. Studies have shown a significant
drop in hydraulic performance when an ESP encounters higher
gas fractions with transients and gas slugs. Performance setbacks
also can be caused by high flowing viscosity or paraffin-rich
crude oils, where startup after a shut in can lead to blockages or
flow restrictions.
Operators looking for simplified gathering systems with
minimum surface infrastructure and facility footprints, and
observing increasingly stringent emission and health, safety

American Oil and Gas Reporter - June 2019

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