Water coning in naturally fractured gas reservoirs often results in excessive water production which can kill a well or severely curtail its economic life due to water handling costs. The purpose of this work was to identify by simulation the factors contributing to water production. A model was developed to represent a single well penetrating a structure with an underlying aquifer. The parametric study was performed by varying 10 properties individually over a representative range. The results were characterized by time to water breakthrough and cumulative water production. It was found that water was able to cone significant vertical distances (250 m) with coning exacerbated by a larger aquifer, higher production rates, and a smaller vertical distance between perforations and the gas-water contact among others. However, in all cases, the ultimate gas recovery was not significantly affected.
Water coning into producing gas wells frequently results in excessive water production during the life of a natural gas reservoir. Coning results from the establishment of a vertical pressure gradient due to flow to the well. This gradient causes the local gas-water contact to rise upward, with the water eventually breaking through to the well.
Excessive water production is often a key factor which limits the economic life of a gas well and forces abandonment of the reservoir at high pressures. High costs associated with the handling and disposal of produced water are incurred. As well, the flow velocities may be insufficient to transport the produced water to the surface. The resulting additional backpressure acting on the formation may eventually kill the well (Coleman et al.).
A key parameter in determining water coning tendency is the vertical to horizontal permeability ratio, kv/kh. Often the presence of shale layers or other tight streaks between the gas-water contact and the well will prevent water coning. The presence of natural fractures, however, often results in high values of kv/kh, providing conditions conducive to water coning.
Relatively few studies have been reported for water coning in naturally fractured reservoirs. The purpose of this work was to identify by reservoir simulation the key parameters governing water production in gas wells penetrating a naturally fractured reservoir. The effects were characterized by time to water breakthrough and cumulative water production. The field values for many of these parameters are not well known. By ascertaining which parameters are most significant, future data acquisition and analysis can be directed at more accurately determining these values. It was especially desired to identify any mechanisms which have a counter-intuitive effect on water production, thus potentially requiring a different operating strategy. The results of this parametric study were subsequently used to explain early water production from a gas well in the Monkman Pass area of N.E. British Columbia (NEBC), illustrated in Fig. 1.
Many studies have been reported on water coning in homogeneous, oil reservoirs. The focus of study has tended to be on the development of correlations for critical rate, time to breakthrough and WOR (water-oil ratio) following breakthrough. A detailed review of this literature can be found in a recent paper by Menouar and Hakim.
Several general trends observed for homogeneous water-oil systems are relevant to this study of gas reservoirs. Correlations developed by Lee and Tung showed that, in general, time to water breakthrough will decrease for the following conditions:
higher offtake rates
shorter perforation intervals