Dry gas injected into wells will vaporize water from the near wellbore zone. The vaporization starts from the well and proceeds outward. Gas flowing to producers is in equilibrium with the reservoir brine, but water will be vaporized because the pressure drop that occurs toward the wellbore increases the ability of the gas to contain water. Thus, there are different mechanisms for injection and production.

For both injection and production, vaporization concentrates solids in the brine. When sufficiently concentrated, minerals will precipitate into the formation. This paper reports on a combined experimental and theoretical analysis on the vaporization portion of this problem for dry gas injection.

Experiments have been performed previously to determine the rate of water vaporization from Berea core samples at uniform initial water saturation (Zuluaga and Monsalve, 2003). The experiments were performed by injecting dry methane into core samples that contained immobile water. This would represent water vaporization in a gas injector.

Effluent water concentration curves showed two vaporization periods: A constant rate period and a falling rate period. The existence of a constant rate period means that the mass transfer within the core is occurring at conditions of local equilibrium. We interpret the falling rate period as the result of a moving capillary transition zone in which the amount of water vaporized decreases slowly because of capillary pressure effects.

We interpret the vaporization results with two traveling wave solutions. The first, which can be solved analytically, assumes that the capillary diffusion coefficient, D, the volume fraction of water in the gas phase, Cwg, and the volume fraction of water in the water phase Cww are constant. For this case, the results of the traveling wave are optimized with the capillary diffusion coefficient D to match the laboratory experiments. The second traveling wave solution must be solved through numerical integration. In this case, the capillary pressure and relative permeability scaling exponents are fitted to match the laboratory experiments. The fitting provides insights into the nature of wetting phase flow at small saturation.

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