Poor displacement efficiency in hydrocarbon formations is often caused by
the natural variation in the mobility of fluids across the reservoir strata.
Historically, completions with cemented casing, packers, conformance
controlling fluids/gels, and selective perforations have been used to mitigate
the disparities in water encroachment over the reservoir interval. Recently,
completion technologies using downhole valves, which allow production and
injection control over multiple zones, have become available. The central idea
is that downhole control may be used to adjust flow distributions along the
wellbore to correct undesired fluid-front movement.
In this paper, we address several technical issues related to downhole
controls. We consider a single system comprising the reservoir, the completion,
the measurement, and the feedback algorithm that adjusts flow-control devices,
with quantitative models for each of the components. Both pressure and
flow-rate control systems are discussed. Downhole control is modeled for
electrical, reversible hydraulic, and unidirectional hydraulic valves. The
design methodology for different valve systems is described and the
disadvantages of hydraulic systems are discussed. In particular, it is shown
that in conjunction with an automated feedback control, hydraulic valves
will oscillate. Computations also show that all other factors remaining equal,
these oscillations occur most easily in low-permeability zones. For
unidirectional hydraulic valves, we also illustrate novel anticipatory control
algorithms that prevent overshooting.
For communicating layered systems, a front movement equation is derived
using perturbation techniques. This technique provides the zone of influence of
wellbore flow-control devices, and illustrates the maximal benefit that may be
obtained through downhole control, thus providing a ready comparison with the
cost of completion.
Two of the common problems that plague waterfloods are poor sweep efficiency
and low contact factor. By our convention, sweep refers to areal displacement.
The contact factor is determined by improper displacement in a direction
orthogonal to reservoir strata. These are discussed by Herbeck et al. (1976).
Here, we use the terms sweep and contact factor to simply
distinguish efficiencies of recovery in the two orthogonal directions.
In a laterally heterogeneous system, or when bedding planes exhibit
anisotropy, poor areal displacement efficiency is expected. That is, for a
given economically acceptable water cut in the production wells, large areas of
the reservoir are left with high oil saturation. This may also be termed as
poor “load balancing.” The literature on the concept of locating missed pockets
of oil goes back to Hurst (1979) and the concept of controlling production was
suggested by Rinaldi (1987). Recent papers [for an example see Graf et al
(2006)] address optimization of intelligent completions. To some extent,
load-balancing problems may be corrected by proper placement of wells, if the
reservoir is characterized perfectly a priori. And incorrect well placement may
be partially compensated by adjusting wellbores’ flow rates with respect to
each other. This is best done by establishing flow-rate control through
variable completions. Thus, for areal nonuniformity and heterogeneity, we
expect a reservoir optimization scheme to prescribe qi
(t) for each well i, given all of the reservoir information
estimated until that point. The smart completion may then be programmed to
follow this qi (t) as closely as possible.
In contrast to poor sweep problems among vertical wells, to improve contact,
one may think of having a well with segmented intervals as shown in Fig. 1.
Each of the strata commingles only at the wellbore. Within the segmented
intervals, a smart completion may be put in place. Through observations or
other modeling means, a feedback-control system to adjust the flow-rates in and
out of each of the independent interval may be implemented. In contrast, one
may also design a feedback system to maintain sandface pressure. Normally, when
control is established in an injection well, the desire is to produce each
layer as fast as possible, limited by the maximum allowable injection pressure.
Uniform frontal displacement may be secondary. Thus, one expects injection at
the maximum allowable pressure pj (t), where
jis the completion interval.
© 2007. Society of Petroleum Engineers
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- Original manuscript received:
12 March 2004
- Meeting paper published:
5 October 2003
- Revised manuscript received:
31 August 2006
- Manuscript approved:
31 August 2006
- Version of record:
20 February 2007