Water blocks and condensate drop out near the wellbore in a gas reservoir can cause rapid production decline. The liquid (water/condensate) is trapped near the wellbore due to strong capillary forces and/or viscous fingering of gas through the liquid. To remove this liquid, alcoholic solvents are injected into the near wellbore area; however, this remedial solution needs to be reapplied in case of any subsequent water or condensate banking in the well. In this paper, we present a preventive and permanent chemical treatment for the removal of water and condensate blocks. Three types of tests have been conducted to evaluate the performance of the chemical system which include contact angle, imbibition and core flow test. A total of 41 chemicals have been tested using contact angle and imbibition tests and only 2 chemicals, A5 and A6 were selected for core flow test as they were stable at high temperature and did not damage the cores excessively during the imbibition tests. The core treated with a solution containing 5% A5 and 95% brine (2-wt% KCl) in the core flow test gave higher clean up of trapped water due to reduction in capillary force. This treatment system also shows a better alteration of the formation wettability from liquid wet to non-liquid wet conditions compared to the other chemical systems tested.
Water blocks occur when large quantities of water enter a low-pressure formation and decrease the relative permeability of oil/gas1–6. A significant decline in productivity can occur due to this phenomenon. Loss of water to the formation can occur during drilling, completion, matrix stimulation, fracturing and other operations that use large amounts of water. A similar phenomenon is also observed in gas condensate reservoirs when the bottomhole pressure is lower than the dew point pressure. In this case, the liquid condensate that drops out of the gas phase near the wellbore region blocks the flow of gas7–15.
Water can be trapped in the formation because of high capillary pressure or viscous fingering of gas through the water. In addition, several other factors such as reservoir heterogeneity, the presence of water sensitive clays, wettability of the formation etc can aid in the trapping of water in the formation. During the production phase, gas displaces the water trapped near the well bore or the fracture face and in the process fingers through the region of high water saturation. The amount of water displaced depends on the drawdown and the capillary pressure of the formation. If the drawdown is low, experiments in low permeability water-wet cores (high capillary pressure) show that greater than 90% of the injected water can be trapped in the formation. After the gas breaks through the water, the remaining water is primarily removed from the formation due to evaporation. The rate of evaporation is dependent on the gas flow rate and can take very long if the flow rate is low 4,16–19.
To improve the clean up of water from the formation, volatile solvents such as alcohols are injected into the formation. Alcohol reduces the capillary pressure by decreasing the interfacial tension between gas and water interface. This capillary pressure reduction helps in displacement of additional water by gas during the displacement stage. After gas breakthrough, the alcohol-water mixture evaporates leading to a faster clean up of water blocks. The only limitation of this method is that the well has to be re-treated with solvents if water block problem reoccurs.20–24