ABSTRACT
Proper management of thin oil rim reservoirs is required to maximize
recovery and minimizes coning tendencies. The objective of this study is
to determine the effect of reservoir and fluid properties on coning
tendencies in thin oil rim reservoirs and to develop numerical
correlations to predict oil recovery and water break through time for
these reservoirs.
Numerical correlations for the prediction of recovery and water
breakthrough time using response surface methodology have been
developed. The thin oil rim reservoir was represented using a generic
simulation box model.
Production rate, horizontal well length, oil viscosity, vertical
landing of well from the gas-oil contact (GOC), vertical permeability
and anisotropy ratio were varied and their effects on oil recovery,
reservoir pressure, water cut and breakthrough time were studied. The
results show that an increase in horizontal well length reduces the
coning tendencies and improves recovery of oil. Increasing viscosity of
oil (reducing oil mobility) increases the coning tendencies whilst
reducing the productivity index of a well hence decreasing recovery. An
increase in the horizontal well landing position from the gas-oil
contact (GOC) results in an increase in water cut. An increase in
vertical permeability and vertical anisotropy ratio both increases the
coning tendencies in thin oil rim reservoirs.
Correlations for the prediction of cumulative oil recovery and water
breakthrough time were developed for reservoir and fluid properties and
well configurations within specific ranges which can be used for
reliable predictions.
The major contribution of this work to knowledge is it presents a
means of using experimental design and response surface methodology to
develop reliable equations for generalized prediction of cumulative
recovery and water breakthrough time in thin oil rim reservoirs without
running simulation models when the required equipment and time is
unavailable.
CHAPTER ONE
1.0 INTRODUCTION
1.1 OVERVIEW
Coning is the result of high pressure gradient around the producing
well which causes the oil-water contact to rise and the gas-oil contact
to depress near the wellbore. Gravitational forces tend to segregate the
fluids according to their densities. However, when gravitational forces
are exceeded by the flowing pressures (viscous force), a cone of water
and/or gas will be formed which will eventually penetrate the wellbore
(Beveridge, 1970). Figure 1.1 is a schematic illustrating the phenomenon
of water coning in a producing vertical well. This dynamic force due to
wellbore drawdown causes the water at the bottom of the oil layer to
rise to a certain point at which the dynamic force is balanced by the
height of water beneath that point. As the lateral distance from the
wellbore increases, the pressure drawdown and the upward dynamic forces
decrease. Thus, the height of the balance point decreases as the
distance from the well bore increases. Therefore, the locus of the
balanced point is a stable cone shaped water oil interface. At this
stable situation, oil flows above the interface while water remains
stationary below the interface (Namani, 2007). This also applies to gas
coning.
The extent of the cone and it stabilization depends on a lot of
reservoir and fluid properties. A lot of correlations have been
developed to predict the rate at which coning will occur for any
conventional reservoir and the breakthrough time for a particular
production rate. However, these correlations have their limitations due
to assumptions made during their development which tends towards
ideality rather than what is actually obtainable.