Significant productivity loss occurs in gas condensate reservoirs due to condensate and water accumulation near the production well. Our experimental study shows that gas relative permeability decreases by more than 95% due to liquid blockage (high water saturation along with condensate accumulation) and the reduction is even more pronounced in presence of mobile water. Significant advances have been made during this study to develop and extend a chemical treatment to reduce the damage caused by liquid blocking in gas condensate reservoirs. The treatment is composed of a non-ionic polymeric fluorochemical in a glycol/alcohol or glycol ether/alcohol solvent mixture. The chemical treatment alters the wettability of water-wet sandstone to neutral wet and increases the gas relative permeability. It also reduces the liquid trapping in pores, which increases the relative permeability to oil or condensate and makes the removal of water blockage from treated zone easier. Selection of solvents to deliver the fluorochemical to the rock surface is critical to the success of the treatment, especially in the presence of high water saturation and high salinity brine. The treatment improved the gas and condensate relative permeabilities by a factor of about 2–4 on liquid blocked outcrop and reservoir sandstone rocks. The improvement in relative permeability after chemical treatment was quantified by performing coreflood experiments at reservoir conditions. The treatment also shows good durability against flowing gas, condensate, brine and solvent. We have developed a chemical treatment that shows great potential to increase production from liquid blocked gas wells with relatively small treatment volumes since only the near-well region needs to be treated. Introduction In gas condensate reservoirs a significant loss in the well productivity is observed when the bottomhole pressure in flowing wells falls below the dew point pressure of the fluid. The buildup of a condensate bank around the well impedes the flow of gas to the well and thus reduces its productivity. Water blocking can cause additional reduction in well deliverability of gas condensate wells. Water can be introduced into the formation during drilling, completion, or workover operations. Water can also flow into a gas-bearing zone from a high-pressure aquifer or a water-bearing zone. Liquids, including both condensate and water, are trapped in pores by capillary forces causing a significant reduction in gas relative permeability and this reduces well productivity. The loss in productivity can be even more pronounced in low permeability reservoirs as very high liquid saturations can be trapped in these reservoirs because of high capillary forces. The reduction in well productivity for gas condensate wells is generally a function of fluid phase behavior and the reduction in relative permeabilities in the near wellbore region. Both phenomena are complex and difficult to predict their effects under reservoir conditions, therefore a great deal of effort has been put into the study of both. Kokal et al. (2000), Pederson and Milter (2004) and Bang et al. (2006a) have studied the effect of water on the phase behavior of gas condensate fluids under reservoir conditions. Relative permeability studies have been done over a wide range of conditions with synthetic fluids (Henderson et al., 2000; Kumar, 2006; Ayyalasomayajula et al., 2003; Bang et al., 2006b) as well as with reservoir fluids (Nagarajan et al., 2004; Mott et al., 2000). Effect of various parameters such as capillary number, non-Darcy effects, fluid composition and rock type on gas relative permeability have been investigated.

Summary During production from gas-condensate reservoirs, significant productivity loss occurs after the pressure near the production wells drops below the dewpoint of the hydrocarbon fluid. Many of these gas reservoirs also have some water accumulation near the wells. This adds significantly to the total liquid blocking. Experiments were conducted using both outcrop sandstone and reservoir cores to measure the effect of liquid blocking on gas relative permeability. A chemical treatment was developed to reduce the damage caused by condensate and water blocking. The treatment is composed of a fluorinated material delivered in a unique and optimized glycol-alcohol solvent mixture. The chemical treatment alters the wettability of water-wet sandstone to neutral-wet and increases the gas relative permeability. The increase in gas relative permeability was quantified by comparing the gas relative permeabilities before and after treatment. Improvements in the gas relative permeability by a factor of approximately two were observed. The alteration of wettability after the chemical treatment was evaluated by measuring the USBM wettability index of treated reservoir cores. Measurements show that a significant amount of the surfactant is adsorbed on the rock surface, which is important for the durability of the treatment. Many attempts have been made to develop effective chemical treatments to mitigate the damage caused by condensate and/or water blocking with little success until now under realistic reservoir conditions. Using inexpensive, safe, and effective solvents was one of the keys to the success of our new approach. Other researchers have mostly tried reactive materials that are subject to complications in downhole applications. We use a nonreactive, nonionic polymeric surfactant that has none of these problems and is robust across a wide range of temperature, pressure, permeability, and brine salinity. We have developed a chemical treatment for liquid blocking that shows great potential to increase production from gas-condensate wells. Compositional simulations indicate that the economics of this treatment process is likely to be very favorable.

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.

During production from gas condensate reservoirs, significant productivity loss occurs after the pressure near the production wells drops below the dew point of the hydrocarbon fluid. Many of these gas reservoirs also have some water accumulation near the wells. This adds significantly to the total liquid blocking. Experiments were conducted using both outcrop sandstone and reservoir cores to measure the effect of liquid blocking on gas relative permeability. A chemical treatment was developed to reduce the damage caused by condensate and water blocking. The treatment is composed of a fluorinated material delivered in a unique and optimized glycol-alcohol solvent mixture. The chemical treatment alters the wettability of water-wet sandstone to neutral wet and increases the gas relative permeability. The increase in gas relative permeability was quantified by comparing the gas relative permeabilities before and after treatment. Improvements in the gas relative permeability by a factor of about 2 were observed. The alteration of wettability after the chemical treatment was evaluated by measuring the USBM wettability index of treated reservoir cores. Measurements show a significant amount of the surfactant is adsorbed on the rock surface, which is important for the durability of the treatment. Many attempts have been made to develop effective chemical treatments to mitigate the damage caused by condensate and/or water blocking with little success until now under realistic reservoir conditions. Using inexpensive, safe and effective solvents was one of the keys to the success of our new approach. Others have mostly tried reactive materials that are subject to complications in downhole applications. We use a non-reactive, nonionic polymeric surfactant that does not have any of these problems and is robust over a wide range of temperature, pressure, permeability and brine salinity. We have developed a chemical treatment for liquid blocking that shows great potential to increase production from gas condensate wells. Compositional simulations indicate the economics of this treatment process are likely to be very favorable. Introduction In gas condensate reservoirs a significant loss in the well productivity is observed when the bottomhole pressure in flowing wells falls below the dew point pressure of the fluid (Afidick et al., 1994; Barnum et al., 1995; Engineer, 1985; Ayyalasomayajula et al., 2005). The reduction in well productivity is caused by the buildup of a condensate bank around the well, which impeded the flow of gas to the well and thus reduces its productivity. 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 (Henderson et al., 2000; Kumar et al., 2006; Kumar, 2006; Ayyalasomayajula et al., 2003; Bang et al., 2006) as well as with reservoir fluids (Nagarajan et al., 2004; Mott et al., 2000). Various parameters such as interfacial tension (Henderson et al., 2000), high flow rates (Kumar et al., 2006; Kumar, 2006; Ayyalasomayajula et al., 2003; Bang et al., 2006; Nagarajan et al., 2004; Mott et al., 2000), non-Darcy effects (Kumar et al., 2006; Nagarajan et al., 2004), fluid composition (Mott et al., 2000) and rock (Mott et al., 2000) have been investigated.

Summary This paper presents a study of gas/condensate hydrocarbon mixtures and the effect of water, methanol, and isopropanol on their phase behavior. Only sparse data are available on the phase behavior of hydrocarbon/water/methanol mixtures at the high temperatures typical of these reservoirs. Such data are needed for compositional reservoir simulations of well treatments to optimize the performance of solvent treatments of blocked wells. Constant-composition expansion (CCE) experiments were performed to measure the phase behavior of hydrocarbon/water/methanol mixtures up to 300°F. The effects of temperature, pressure, and water and methanol concentration on the phase behavior were measured. The Peng-Robinson equation of state (EOS) was used to model hydrocarbon/water/methanol mixtures. The binary interaction parameters were tuned to fit the data and were found to show a linear variation with temperature. The binary interaction parameters and temperature-dependent volume-shift parameters are the key parameters to model these complex polar mixtures. Both the classical van der Waals and the Huron-Vidal (Huron and Vidal 1979) mixing rules were used and were found to give good agreement with the data. Phase-behavior experiments performed on hydrocarbon/water/isopropanol mixtures showed that isopropanol decreases the aqueous-phase volume fraction and increases the liquid-hydrocarbon-phase volume fraction compared with the analogous hydrocarbon/water/methanol mixtures. These data are needed to predict the conditions under which methanol/isopropanol treatments can be applied successfully in gas wells to remove water and condensate blockage.