Summary
We use a pore-scale network model in conjunction with conventional
reservoir-scale simulations to investigate wettability variation within an
oil/water transition zone. If the initial water saturation within the
transition zone is controlled by primary drainage, we predict that initial
production behavior is the same regardless of wettability. However, if the
initial water saturation has been modified by movement of the free water level
(FWL) following reservoir filling, then both the initial water saturation and
production behavior are different depending upon wettability. In this
case, the wettability of the reservoir may be estimated using in-situ
measurements. Moreover, wettability variation may yield anomalous dry oil
production from the transition zone. Over longer production timescales,
wettability variation can result in high displacement efficiency during
waterflooding. Assuming that the reservoir is uniformly water-wet or
oil-wet, or using empirical hysteresis models, leads to a significant
underestimate of recovery.
Introduction
Many oil reservoirs contain a significant transition zone, in which fluid
saturations and production characteristics vary with depth.1–5 Typically, the
top of the transition zone contains oil in the presence of connate (immobile)
water, while the base of the transition zone is fully water
saturated. Within the transition zone, both oil and water are usually
mobile. The transition zone may vary from a few meters to several hundred
meters in thickness and contain a significant proportion of the oil in
place. The transition zone often exhibits variable wettability, with the
most water-wet conditions found at the base and the most oil-wet conditions at
the top.4–9 The wettability of a crude oil/water/rock system depends upon
factors such as the mineralogy of the rock, the composition of the oil and
water, the temperature, and the initial water saturation.9–15 Wettability
variations within a transition zone are principally controlled by the increase
in water saturation with depth.4–9 At the top of the transition zone the
oil saturation is high, so more pores and throats are contacted by
oil. These pores and throats can become oil-wet if surface-active
components such as asphaltenes within the oil are adsorbed onto the mineral
surfaces.9–15 At the base of the transition zone the pores and throats are
not contacted by oil, so they remain water-wet. The reservoir is least
water-wet (most oil- or mixed-wet) at the top of the transition zone, becoming
progressively more water-wet with depth as the water saturation
increases.4–9
Wettability can have a significant impact on flow during oil recovery, and
upon the volume and distribution of the residual oil.16–19 However, the impact
of wettability variation associated with an oil/water transition zone is poorly
understood. Masalmeh4 measured oil relative permeability in cores that had
been aged at different initial water saturations. He found that the oil
relative permeability at a given water saturation increased with initial water
saturation (increasingly water-wet conditions). Based on these findings,
he suggested that oil may be more mobile toward the base of a transition zone,
yielding higher oil recoveries than conventionally predicted. However, he
did not measure the variation in water relative permeability with initial water
saturation (and therefore wettability), which is much more significant and can
have a profound influence on waterflood efficiency.20 Parker and Rudd5
suggested that wettability alteration may yield anomalous dry oil production
from a transition zone, but provided only a qualitative explanation of the
pore-scale mechanisms responsible.
The aim of this study is to investigate and predict the effect on production
of wettability variation associated with an oil/water transition zone, using a
pore-scale network model in conjunction with conventional reservoir-scale
simulations. We use a 3D network model, which combines a physically based
pore-scale model of wettability alteration21 with a network representation of a
Berea sandstone.22,23 The network is reconstructed directly from a sample of
the sandstone, so the pore-size distribution and coordination number are fixed
and are not “tuned” to match experimental data. We demonstrate that this
network model can successfully predict experimental relative permeability data
for water-wet Berea sandstone24 and waterflood recoveries for mixed-wet
Berea.19 We therefore have confidence in its ability to capture and
predict the effect of wettability alteration on relative permeability and
capillary pressure. The network model is a tool that allows us to
investigate wettability variations much more quickly and efficiently than
laboratory experiments.
We begin with a detailed analysis of initial production behavior from a
transition zone. We find that, if the initial water saturation is governed
by the balance of gravity and drainage capillary forces, wettability variation
makes no difference to production behavior, because this is dictated by the
drainage relative permeability curves. These are the same irrespective of
wettability alteration following oil migration into the
reservoir. However, if the FWL migrates upward following wettability
alteration (for example, because of leakage of hydrocarbons from the
reservoir), then the initial water saturation is governed by the balance of
gravity and waterflood capillary forces, and production behavior is dictated by
the waterflood relative permeability curves. These depend upon the
wettability of the reservoir. Consequently, the initial water saturation
and production behavior is different depending on whether wettability
alteration has occurred. In this case, the wettability of the reservoir may be
determined from in-situ measurements. Moreover, wettability alteration may
yield anomalous dry oil production from the transition zone.
We then perform a simulation study to investigate longer production
timescales and find that wettability variation can result in high displacement
efficiency during waterflooding. Assuming that the reservoir is uniformly
water-wet or oil-wet, or using empirical hysteresis models, leads to a
significant underestimate of recovery.
© 2005. Society of Petroleum Engineers
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History
- Original manuscript received:
9 January 2003
- Revised manuscript received:
10 March 2005
- Manuscript approved:
3 April 2005
- Version of record:
15 June 2005
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