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.

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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 Many gas wells suffer a loss in productivity because of liquid accumulation in the near-wellbore region. Chemical stimulation may be used as a remedy by altering the wettability to nonliquid wetting. Successful treatments decrease liquid trapping, increase fluids mobility, and improve the well's deliverability. This paper presents the first effective chemical treatment to mitigate liquid blocking in carbonate gas reservoirs. Screening tests were developed to quickly and effectively identify suitable chemicals from a large pool of compounds. X-ray photoelectron spectroscopy (XPS) measurements and drop-imbibition tests with water and n-decane were found to be necessary but not sufficient indicators of the effectiveness of the chemicals and were used as screening tests. An integral part of the development of the treatment solution was the selection of a solvent mixture capable of delivering the fluorinated chemical to the rock surface. The treatment solution, mixture of chemical dissolved in solvent, must be stable in the presence of both brine and condensate so that it will not precipitate and will not reduce permeability of the rock. We acquired measured relative permeability values in Texas cream limestone (TCL) cores from high-pressure/high-temperature (HP/HT) coreflood experiments before and after treatment. Measurements were made using a pseudosteady-state method with a synthetic gas/condensate mixture. To enhance the durability of the treatment, a special amine primer is introduced. The gas relative permeability increased considerably (approximately 80%) after the treatment compared to that before treatment. This increase remained substantial, greater than 60% after injection of more than 1,000 pore volumes (PV) of gas/condensate mixture. We found an even greater increase in gas relative permeability during unsteady displacement of water by methane. The improvement remained after injecting 20 PV of brine and increasing the temperature in the treated core from 175 to 275°F. The chemical treatment developed in this research can be applied to increase well deliverability of both gas and condensate in the field, providing that it is properly designed by considering key parameters such as reservoir pressure and temperature, brine salinity, and initial water saturation.

In gas condensate reservoirs, considerable productivity loss occurs after the pressure near the production wells drops below the dew point of the hydrocarbon fluids. Over the years, several methods have been proposed to restore gas production rates after a decline in well productivity owing to condensate and/or water blocking. These methods such as gas recycling, hydraulic fracturing and solvent injection have shown to restore the production on a temporary basis only. Altering the wettability of reservoir rock using fluoro-chemical treatments has proved to be a viable and permanent solution to this problem. The selection of these treatments from a large pool of potentially effective chemicals requires extensive laboratory testing which requires time and money.In this paper, we present data that correlates changes in wettability with improvements in relative permeability. Imbibition, contact angle and X-ray photoelectron spectroscopy (XPS) tests along with coreflood results are used to characterize wettability changes. XPS tests, drop tests and core flood experiments were conducted and correlated with each other. It is shown that XPS analysis and imbibition tests provide a quantitative measure of chemical adsorption and surface modification, but only a qualitative measure of the possible change in relative permeability. As such these simple analytical tools may be used as a screening tool. A positive but imperfect empirical correlation was obtained with results from core flood experiments. The varying concentration of fluorine observed on the rock surface was found to be directly correlated to the wettability change in the rock, which in turn is responsible for improving the deliverability of wells in gas condensate/volatile oil reservoirs.The method discussed in this paper can be successfully used to identify chemical treatments that can change rock wettability and, therefore, relative permeability. This provides a simple and inexpensive way to screen chemicals as wettability altering agents and relative permeability modifiers. In this way the number of HTHP core floods needed is minimized which saves time, cost and effort. IntroductionGas condensate reservoirs are becoming more common as the petroleum industry goes to greater depths to explore for oil and gas. When we compare dry-gas reservoirs with gas-condensate reservoirs, there are many factors which affect the performance of gas-condensate reservoir during the exploitation process that need to be understood. As the reservoir pressure declines below the dew point of the fluid, a liquid rich phase starts to drop out of the gas phase. This liquid rich phase is termed "condensate" and the phenomenon is called "condensate banking". Since the largest pressure drop occurs near the producing wells, the formation of a condensate phase usually occurs as a near well bore phenomenon. As the pressure continues to drop, the liquid continues to accumulate occupying the rock pores leading to a decrease in the effective permeability to gas.Several cases have been reported i...