Clean-up of Water Blocks in Low Permeability Formations

Abstract

Abstract Water-blocked low permeability gas formations with drawdown pressures comparable to capillary entry pressures can take a very long time to clean up. The clean up of water blocks in gas wells occurs in two regimes: displacement of the fluids from the formation followed by vaporization by the flowing gas, which becomes under-saturated as the pressure decreases. This work aims to study the effect of rock permeability, wettability, temperature, drawdown and surfactants on the clean up of cores containing brine. The effectiveness of using solvents for cleanup under different conditions has been evaluated by comparing gas relative permeabilities with and without methanol. Gas displacement experiments were conducted on cores fully saturated with brine. The gas relative permeability increases with pore volumes of gas injected for long periods of time (up to 100,000 PV) at ambient temperature. The addition of methanol, increasing temperature and increasing core permeability resulted in faster cleanup after about 50 to 100 PV of gas flow. The change of wettability of the rock from water-wet to oil-wet also resulted in faster recoveries in gas relative permeability. Our observations show that the clean up of water-blocks can be improved by:Influencing the displacement of brine, i.e. by changing the wettability and,By increasing the rate of vaporization by introducing volatile solvents such as methanol. It is found that changing wettability also has an impact on the rate of vaporization of the brine and methanol. The study quantifies the effects of factors such as rock permeability, wettability, surface tension, and temperature on gas relative permeability. The results of this study will help in selecting strategies for clean-up of water blocks created due to various operations such as drilling and fracturing, and making recommendations for the use of surfactants or solvents for well treatments for removing water blocks. Introduction Invasion of aqueous drilling, completion or fracturing fluids during well completion, workover or stimulation operations can reduce the relative permeability to gas and thereby cause a water-block. Cimolai et al.1 report that gas reservoirs, which were under-saturated, readily accommodated the invaded aqueous fluids creating a water block. The gas phase relative permeability depends on the water saturation in the porous medium and the fractional flow characteristic of gas in the presence of water. The water-block can be removed by reducing the saturation of the invaded fluid in the well bore region and/or by affecting the fractional flow characteristics of the gas. Studies show that the clean up of water-blocks in gas wells is faster if the absolute permeability of the formation is high (Tannich2). In the case of low permeability formations the capillary pressure tends to be high because of the smaller pore sizes. However, Holditch3 showed that when the drawdown pressures are very high the capillary pressure end effects do not affect the gas flow rates even in low permeability formations. Studies by Parekh4 show the effect of relative permeability curve exponents on the clean up of water block is significant with faster clean up for high values of Corey exponents. Abrams and Vinegar5 show that the effect of additives such as alcohol and/or surfactants does not create a significant improvement in the final gas flow when the drawdown pressures are significantly greater than the capillary entry pressures. Earlier studies by McLeod et al.6 conclude that alcohols increase the water recovery and clean up rate in gas wells when used as part of the stimulation fluid. The authors attributed the increase to better displacement of the fluids from the formation due to a decrease in interfacial tension and also the volatility of alcohols. A recent study by Kamath et al.7 shows that the clean up of water blocks in gas wells occurs in two regimes: displacement of the fluids from the formation followed by vaporization by the flowing gas which becomes under-saturated as the pressure decreases. The first phase of liquid removal is an immiscible displacement of water by gas, which solely depends on the fractional flow characteristics. The second phase is a continual evaporation of the invaded water by the expanding gas flow. The equation for gas saturation change given in the paper by Kamath et al,7 shows that even if the entering gas has a relative humidity of 100 percent the water saturation in the core decreases as more gas is injected. This is because of evaporation from the core due to the pressure drop across the core.