American Oil and Gas Reporter - January 2023 - 82

tend the recovery factor to at least 22%
and keep existing facilities and infrastructure
unchanged.
A satellite with production and test
manifolds and a three-mile flowback
pipeline to the process facility was selected
for installing a multiphase pump system.
The field has 24 producing wells operating
with a blend of rod pumps and ESPs. Oil
gravity is 29 degrees API, water cut is
close to 90% and the gas volume fraction
averages 68%.
With declining reservoir pressure, the
artificial lift systems were subject to declining
reservoir pressure, and in many
cases, the downhole pumps were not able
to buck the flowline and gathering system
backpressure and had to be shut in.
A 300-hp multiphase pump skid was
selected, including a seal support system
for double mechanical seals, controls and
automation for remote operation. For outside
protection, the skid was housed
within a protective cage.
Figure 4 shows the results of the installation
and the level of drawdown
achieved using the multiphase pump. The
FIGURE 4
Gathering System and Draw Down (Onshore Brazil Field)
lowered gathering system backpressure
had a determined effect on the submergence
of the downhole pumps: the submergence
for rod pumps was doubled
and the ESPs were able to produce safely
well above the bubble point for uninterrupted
production. The field reached an
impressive 22% recovery factor after one
year of operation and the economics of
this installation speak loudly to the potential
advantage of adding multiphase
pumps to older and declining fields.
Mitigating Liquids Logging
A producer of liquid-rich gas wells in
Colorado was looking for a solution to
combat liquid-logged wells that had significant
impact on steady-state production.
As an initial step, the wells had a gas lift
system added to lighten the density of the
liquid column to get to critical velocity
needed to offload the liquids. As the wells
were aging, the reduced natural pressure
led to difficulties in achieving critical velocity
and the operator investigated an alternative
solution with a blowdown unit
(BDU) using a multiphase pump.
The operator was interested in a
portable solution as a well service unit
that could be used across multiple production
sites as needed. Because the
terrain was quite hilly, the unit had to
be light enough to be towed by a standard
2.5-ton pickup truck. Most of the
well sites had no access to utility power,
so the multiphase pump was powered
by a natural gas engine taking fuel gas
from production, which together with
a speed increaser, added weight to the
pump skid.
The BDU was hooked up to a shutin,
liquid-loaded well (or multiple wells)
and started up with equal pressure at
both the inlet and outlet. For starting
and building differential pressure and
moving the gas, the multiphase pump
utilized liquids stored in the liquid
knockout boot and recirculated until the
gas pocket was evacuated and liquid
started coming from the tubing. The
pressure differential accelerated the tubing
velocity and unloaded liquids at an
increasing rate as the BDU pressure
boost began overcoming gathering sysManifold
CP-1391 =
responsible for 3.4%
of Oil Production of
the Carmópolis Field
Panelas Satellite
Station
~700m
About 5km
Manifold
CP-1391
Bonsucesso Process
Station
Well/Artificial
Lift Method
CP-1464/SRP
Increasing of the downhole pump submergence
20
CP-1461/ESP
Reduction of the motor current-10% (less DP required on ESP)
and increasing of the ESP submergence
82 THE AMERICAN OIL & GAS REPORTER
8
9.3
4
90
Pwh before
(kgf/cm2
)
11
Pwh after
(kgf/cm2
5
)
Pcasing before
(kgf/cm2
)
9.4
Pcasing after
(kgf/cm2
)
4.4
Sub before
(m)
130
Sub after
(m)
265
American Oil and Gas Reporter - January 2023

Table of Contents for the Digital Edition of American Oil and Gas Reporter - January 2023
