Abstract
When the bottomhole pressure (BHP) of volatile oil reservoirs falls below the
bubblepoint pressure, two phases are created in the region around the wellbore,
and a single phase (oil) appears in regions away from the well. The oil
relative permeability reduces towards the near-wellbore region due to
increasing gas saturation. This behaviour is quite similar to a gas-condensate
reservoir below the dew-point, where the gas relative permeability is reduced
due to the existence of a liquid bank around the wellbore. There are numerous
publications in the literature concerning the behaviour diagnostic and well
deliverability calculation in the case of gas-condensate reservoirs. However,
the behaviour of volatile oil reservoirs is not well understood.
This paper aims at understanding the behaviour of volatile oil reservoirs. We
used reservoir compositional simulations to predict the fluid behaviour below
the bubblepoint, and then exported the flowing bottomhole pressure to a well
test package to diagnose the existence of different mobility regions. In this
study, the applicability of the two-phase pseudo-pressure method on volatile
and highly volatile oil reservoirs was investigated, and it was found that this
method is a very powerful tool for the prediction of true permeability and
mechanical skin. Also, this method is capable of distinguishing between
mechanical skin and condensate bank skin, which can be very helpful for
designing after-drilling well treatment and IOR process designs.
Introduction
In gas-condensate reservoirs, retrograde condensation occurs when the flowing
bottomhole pressure declines below the dew-point pressure, creating four
regions in the reservoir with different liquid saturations. Away from the well,
an outer region has the initial liquid and gas saturation. Next, nearer the
well, there is a rapid increase in liquid saturation and a decrease in the gas
mobility where the liquid still is immobile. Closer to the well, an inner
region is formed where liquid saturation is higher than the critical condensate
saturation and both oil and gas phases are mobile. Finally, in the immediate
vicinity of the well, there is a region with a lower liquid saturation due to
capillary number (the ratio of viscous to capillary forces) effects. Such a
region has been inferred from a number of experimental core studies at low
interfacial tension and high flow rates. The existence of the fourth region is
important because it counters the reduction in productivity caused by liquid
drop-out. The various mobility zones described above can be identified by well
test analysis, using a variety of analytical and numerical
models(1-3).
Well test analysis is now commonly used to identify and quantify near-wellbore
effects, reservoir behaviour (i.e. zones of different mobilities and
storativities) and reservoir boundaries. Finding all of this information from
well tests in gas-condensate reservoirs, however, is challenging. This is due
to changes in the composition of the original reservoir fluid and the impact of
wellbore dynamics. Nonetheless, gas-condensate flow behaviour is now reasonably
well understood.
© 2009. Petroleum Society of Canada (now Society of Petroleum Engineers)
View full textPDF
(
2,434 KB
)
History
- Original manuscript received:
5 November 2008
- Revised manuscript received:
30 June 2009
- Manuscript approved:
4 August 2009
View Cart
