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.
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.
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