The chemical treatment (mixture of solvents and a surfactant) to mitigate liquid block (condensate and or water) in gas or condensate well has been tested in the field and shows promising prospects as a long term solution. The injected solvents remaining in the formation after the treatment may reduce condensate production significantly when production resumes. It is therefore of utmost concern to predict correctly how soon the solvents injected will flow back into the well and in which phase will the solvents flow back. A three-phase flash is needed to model the phase behavior and partitioning that occurs during the injection and flow back of treatment solutions. All previous modeling studies were conducted using a simulator with a two-phase flash. To date, the compositional effects of solvents and chase gas during the injection and flow back period have not been understood and modeled adequately.
Initial efforts to use UTCOMP with its three-phase flash option to simulate this process were not successful due to the problems with inconsistent phase labeling. A general composition-dependent relative permeability model was developed and makes it unnecessary to identify phases. The molar Gibbs free energy was used as measure of phase composition and as interpolation parameter for relative permeability model. This model was implemented in UTCOMP. The updated simulator simulated the same problem successfully.
The correct modeling of the phase behavior makes is possible to a correct projection of the solvents flow back period during the design of chemical treatment. This also makes it possible to evaluate the impact of different solvents and chase gases on the flow back period of solvents. Two groups of eligible solvents along with four kinds of chase gas option (no chase gas, N2, CO2, CH4) were evaluated using a field case. It shows that heavy component of treatment solution flows back significantly from aqueous phase in contrast to previous results from 2-phase flash that heavy components of solvents flows back in oil phase. Light components presents in all three phases in contrast to previous results from 2-phase flash that light solvents flows back only in gas phase. More insight was gained regarding the eligibility of solvents, chase gas, and their combinations.
Li and Firoozabadi (2000) proposed an approach for stimulating gas condensate wells by changing the rock wettability towards non-liquid wetting in the near well-bore region. Kumar et al. (2006) reported improvement in gas and condensate relative permeability when Berea and reservoir sand stone cores were treated using a non-ionic surfactant. Bang et al. (2007) did extensive experiments for sandstone with a variety of new solvents containing a fluorocarbon polymeric surfactant. These eligible solvents included ethanol, isopropanol (IPA), 2-Butoxyethanol (2-BE) and propylene glycol (PG). Ahmadi et al. (2010) reported successful wettability alteration in Texas Cream limestone and Silurian Dolomite cores. Effective solvent mixture was developed for delivering fluorinated chemical to the rock surface. Enhancement in measured gas and condensate relative permeability after treatment was considered to evaluate the effective of different treatments.