Summary
Relatively few field installations of a dual-electric submersible-pump
(DESP) completion have been reported. In general, the purpose of the second
pump was either to increase the pumping capacity, or to act as a backup to
improve the reliability of the pumping system. However, DESPs potentially can
address a much wider range of reservoir management challenges. This paper will
analyze the performance of a DESP in a range of reservoir scenarios. It will
show how DESP performance can be modeled by use of commercially available,
coupled, well-performance and reservoir-simulation tools.
Four DESP applications were analyzed. Where possible, the robustness of the
numerical-modeling results will be compared with analytical predictions. DESPs
gave improved oil production and recovery in reservoirs with strong aquifer
support and became progressively more attractive in a layered-reservoir
scenario as the pressure difference between the production zones increased.
However, while DESPs had no significant advantages in a long, horizontal well
placed in a homogeneous reservoir, they can increase recovery in a tilted,
layered reservoir. A slim, deepwater well completed with a lower-capacity
downhole pump and a larger (multiwell) seabed booster pump was shown to be a
potentially attractive solution for some reservoir developments.
This work provides a comparison of the drivers for the choice of a single
electric submersible pump (SESP) and a DESP in the scenarios studied. It
illustrates a modeling methodology and provides DESP-selection guidelines, thus
aiding the increased application of this technology.
Introduction
Artificial-lift methods, including electric submersible pumps (ESPs), are
required when a well ceases to flow naturally or when the production rate is
too low to be economical. ESPs boost the pressure of the produced fluid,
allowing an increase in the well drawdown and providing the additional energy
required for the reservoir fluids to flow. For the purposes of this paper, we
will assume that ESPs are the preferred form of artificial lift. The typical
ESP installation employs a single multistage pump driven by an electric motor
(called a SESP in this paper). Currently, it is technically possible to employ
more than one pump/motor set in the tubing string (i.e. a DESP).
In general, applications of the second pump have been either to increase the
pumping capacity (Moreno et al. 1998) or to act as a backup to improve the
reliability of the pumping system (Sarawyn 2003; Horn et al. 2004). DESPs have
been used for managing reservoir issues such as water coning (Gonzalez et al.
2003) and multiple production zones (Almeida et al. 2002; Magherini et al.
2003). A DESP system deployed in a well experiencing water coning resulted in
an improved oil rate (Gonzalez et al. 2003). However, the water cut remained
high (65 to 70%) in the pump producing from the upper oil zone, while some 4%
oil was recorded from the bottom water zone. The heterogeneous nature of the
reservoir properties was identified as the reason for such behavior (Gonzalez
et al. 2003). A DESP system resulted in an increased production in a well with
multiple production zones with different reservoir properties such as
permeabilities and pressures (Almeida et al. 2002; Magherini et al. 2003). The
lack of reporting of reservoir-performance analysis using numerical modeling in
such applications illustrates the need for understanding of reservoir behavior
while selecting a DESP system.
This paper will explore the potential for DESP application for a range of
reservoir-performance scenarios where the use of an SESP results in a lack of
“pressure balance” along the wellbore. One such well-known example is the
effect of friction and pressure drop along a horizontal well. There are
reported field examples (Erlandsen 2000; Glandt 2005) and numerical reservoir
models (Yu et al. 2000; Ebadi et al. 2005; Sinha et al. 2001) where
“flattening” the pressure profile by use of one or more downhole flow
restrictions installed across the completion interval had shown accelerated
production and increased recovery. At its most basic, an ESP increases the well
drawdown and provides additional energy to lift the well fluid to the surface.
In principle, installation of a sensitively controlled DESP across the
completion interval is also capable of modifying the drawdown profile in a
similar manner. This realization leads us to examine if they can be used to
improve well performance, particularly from a reservoir-performance point of
view.
Four different possible applications of DESPs will be analyzed in this
paper:
- Commingling production from zones with different pressure regimes.
- Control of water coning by producing from both oil and water zones in
bottomwaterdrive reservoirs.
- Control of water cresting in long horizontal wells by use of DESPs at heel
and toe.
- Installation of a reduced-power downhole pump at the production zone
supplemented by a higher-capacity pump at the seabed for production from
deepwater oil reservoirs.
Simple models have been used in this study. This enabled a general
understanding of the main drivers for the selection of DESP systems for a
particular application to be developed by use of sensitivity analysis. We have
limited the ESP-selection process to ensuring that it operated within the
recommended efficiency range throughout its production lifetime.
Realistic economic analysis of ESP application has to include the pump’s
initial purchase and installation cost, but must also account for the longevity
or failure frequency of the ESP. This frequency will depend on the correctness
of the choices made during the ESP selection process, the severity of the
operational conditions, the skill of the wellsite installation staff and of the
production operators. An independent-backup pump would be justified if frequent
ESP failure were expected because it would allow the longest period of
uninterrupted production from the reservoir.
© 2008. Society of Petroleum Engineers
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History
- Original manuscript received:
19 June 2006
- Meeting paper published:
12 June 2006
- Revised manuscript received:
23 May 2007
- Manuscript approved:
30 June 2007
- Version of record:
20 May 2008
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