Summary
It has been demonstrated, first by this laboratory and subsequently by other
researchers, that the gas and condensate relative permeability can increase
significantly by increasing rate, contrary to the common understanding. There
are now a number of correlations in the literature and commercial reservoir
simulators accounting for the positive effect of coupling and the negative
effect of inertia at near-wellbore conditions. The available functional forms
estimate the two effects separately and include a number of parameters, which
should be determined with measurements at high-velocity conditions.
Measurements of gas/condensate relative permeability at simulated near-wellbore
conditions are very demanding and expensive.
Recent experimental findings in this laboratory indicate that measured
gas/condensate relative permeability values on cores with different
characteristics become more similar if expressed in terms of fractional flow
instead of the commonly used saturation. This would lower the number of rock
curves required in reservoir studies. Hence, we have used a large data bank of
gas/condensate relative permeability measurements to develop a general
correlation accounting for the combined effect of coupling and inertia as a
function of fractional flow. The parameters of the new correlation are either
universal, applicable to all types of rocks, or can be determined from commonly
measured petrophysical data. The developed correlation has been evaluated by
comparing its prediction with the gas/condensate relative permeability values
measured at near-wellbore conditions on reservoir rocks not used in its
development. The results are quite satisfactory, confirming that the
correlation can provide reliable information on variations of relative
permeability at near-wellbore conditions with no requirement for expensive
measurements.
Introduction
The process of condensation around the wellbore in a gas/condensate
reservoir, when the pressure falls below the dewpoint, creates a region in
which both gas and condensate phases flow. The flow behavior in this region is
controlled by the viscous, capillary, and inertial forces. This, along with the
presence of condensate in all the pores, dictates a flow mechanism that is
different from that of gas/oil and gas/condensate in the bulk of the reservoir
(Danesh et al. 1989). Accurate determination of gas/condensate relative
permeability (kr ) values, which is very important in
well-deliverability estimates, is a major challenge and requires an approach
different from that for conventional gas/oil systems.
It has been widely accepted that relative permeability (kr
) values at low values of interfacial tension (IFT) are strong functions of IFT
as well as fluid saturation (Bardon and Longeron 1980; Asar and Handy 1988;
Haniff and Ali 1990; Munkerud 1995). Danesh et al. (1994) were first to report
the improvement of the relative permeability of condensing systems owing to an
increase in velocity as well as that caused by a reduction in IFT. This flow
behavior, referred to as the positive coupling effect, was subsequently
confirmed experimentally by other investigators (Henderson et al. 1995, 1996;
Ali et al. 1997; Blom et al. 1997). Jamiolahmady et al. (2000) were first to
study the positive coupling effect mechanistically capturing the competition of
viscous and capillary forces at the pore level, where there is simultaneous
flow of the two phases with intermittent opening and closure of the gas passage
by condensate. Jamiolahmady et al. (2003) developed a steady-dynamic network
model capturing this flow behavior and predicted some kr
values, which were quantitatively comparable with the experimentally measured
values.
© 2006. Society of Petroleum Engineers
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History
- Original manuscript received:
18 November 2003
- Revised manuscript received:
18 October 2005
- Manuscript approved:
10 October 2006
- Version of record:
20 December 2006
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