One of the common causes of gas wells productivity loss is attributed to liquid accumulation near the wellbore over the production life of the wells. For gas condensate reservoirs, when the bottomhole pressure falls below the dew point pressure, liquid hydrocarbon drops out of the gas phase, residing in the near wellbore region and causing condensate block. Fracturing fluid also contributes to liquid blockage as only 5 to 30% of fracturing fluids are recovered from the reservoir. For a tight shale formation where the pore sizes are as small as nanometers, capillary pressure is large enough to cause liquid entrapment in the pore body reducing the relative permeability to the gas phase.
A variety of methods such as gas cycling, super critical CO2 injection, solvent injection, and wettability alteration using fluorinated surfactants/polymers have been suggested to treat liquid block or banking (i.e., water and condensate). However, these methods are either not effective or expensive, and do not provide a good return on investment. As capillary pressure depends on surface/interfacial tension (ST/IFT) and the contact angle, a treatment method that combines the effect of ST/IFT reduction and wettability alteration can be applied to lower capillary pressure, thus, to enhance liquid unloading. In addition, reducing the ST between gas and the liquid phase (water/gas condensate) will increase the carrying capacity of the gas phase with respect to the banked liquid phase.
This paper presents a practical laboratory testing procedure developed to screen and recommend cost effective production enhancement formulations to treat liquid blocking. Based on laboratory test results obtained from this testing procedure, a non-fluorinated production enhancement formulation was recommended for a field trial. The recommended formulation was tested at two gas wells: one vertical and one horizontal in North Texas. The proposed formulation was used in the fracturing fluids when the wells were re-fractured. Production data from the two wells have shown a sustained increase in gas production and water recovery rate. The lessons learned here can be used as a guideline to increase production life of existing gas wells and to maximize hydrocarbon (gas and associated condensate) recovery rates.