Improving Productivity of Hydraulically Fractured Gas Condensate Wells by Chemical Treatment

Abstract

Abstract Most gas condensate wells, including hydraulically fractured wells, are operated at pressures below the dew point pressure of the reservoir causing condensate to drop out and accumulate near the wellbore, thus blocking the gas production. Even for very lean gas condensate fluids, once the bottom hole flowing pressure falls below the dew point pressure, the condensate bank forms in a matter of months and leads to a rapid decline in production from these wells. In hydraulically fractured gas condensate wells, condensate can build up to very high saturations in and around the fracture which significantly reduces the productivity of these wells. Two-phase gas condensate flow measurements have been conducted under reservoir conditions in a propped fracture to study the damage caused by condensate blocking in fractures. An in situ chemical treatment has been developed to reduce the damage caused by liquid blocking of hydraulically fractured wells by altering the wettability of the proppants to neutral wet, thus reducing the residual liquid saturations and increasing gas relative permeability. A fluorinated surfactant in a glycol-alcohol solvent mixture was found to improve the gas and condensate relative permeabilities measured on propped fractures by a factor of about 2 under reservoir conditions. Introduction In gas condensate reservoirs, when the bottomhole pressure in flowing wells falls below the dew point pressure of the fluid, a liquid hydrocarbon phase commonly referred to as condensate is formed and is subsequently trapped by capillary forces. The liquid condensate, along with the connate water that is present, continues to accumulate in the rock pores thus impeding gas flow, until a critical liquid saturation is reached that is similar to the residual oil saturation that would form in the same rock under the same flow conditions. Once the critical liquid saturation is exceeded, both the condensate and gas flow towards the wellbore. The liquid continues to accumulate until a steady-state saturation is reached that is somewhat higher than the critical liquid saturation. Condensate banking can reduce the well productivity significantly, in several instances by a factor of 2 to 4. Afidick et al. (1994), Barnum et al. (1995), Engineer (1985) and Ayyalasomayajula et al. (2003) have reported field data that show significant productivity loss due to condensate accumulation. Since the reduction in well productivity is primarily associated with the reduction in gas relative permeability, a great deal of effort has gone into measuring and modeling the relative permeability of gas-condensate fluids. Initially, the studies were done at low pressure and temperature (Ham and Eilerts, 1967). Later studies were done at reservoir conditions with synthetic fluids (Kumar et al., 2006; Ayyalasomayajula et al., 2003; Henderson, 1998) as well as with reservoir fluids (Nagarajan et al., 1998). Various parameters such as interfacial tension (Haniff and Ali, 1990), high flow rates (Henderson et al., 2000; Kumar, 2006), non-Darcy effects (Henderson et al., 2000; Bang, 2007), fluid composition (Bang et al., 2006) and rock type (Bang et al., 2006) have been investigated. Several strategies have been tried and tested for stimulating gas-condensate wells with limited success (Anderson, 2005). Gas cycling (Aziz, 1983; Harouaka and Al-Hashim, 2002) allows the pressure to be maintained above the dew point but may not be economical, especially late in the life of the reservoir when large quantities of injected gas are required to maintain the pressure above dew point.