Recent research indicates that even small viscous transverse pressure gradients can increase the rate of surfactant imbibition into the matrix of a fractured reservoir. However, surfactants are commonly tested using static imbibition cells without any imposed pressure gradient. Therefore, the effect of viscous pressure gradients was investigated by conducting a series of surfactant corefloods using fractured Silurian Dolomite and Texas Cream Limestone cores. The viscosity of the surfactant solution was increased by adding polymer or by changing the salinity of the aqueous surfactant solution, which affects the in-situ microemulsion viscosity. The fractured cores had a permeability contrast between the fracture and the matrix ranging from 2500 to 90,000. Non-fractured corefloods were also performed and compared with the fractured corefloods. The more viscous surfactant solutions achieved greater oil recovery from the fractured carbonate cores. These results indicate that a viscous microemulsion can serve as a mobility control agent in naturally fractured reservoirs (NFRs) that is analogous to mobility control with foams and polymers, but with less complexity and cost.

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We developed and investigated the effectiveness of new multifunctional foaming agents (MFAs) for production enhancement in oil wells with gas lift or high gas-oil ratio, high water cuts (>30%), and very high conditions of temperature (180°C), hardness (180,000 ppm), and salinity (400,000 ppm TDS). The efficiency of the MFAs was tested using two laboratory methods, which are conducted at close to wellhead and downhole conditions of temperature and pressure, respectively. These methods were used to optimize the development of the MFAs and their field application design.

We describe the first field applications of a new multifunctional foaming agent (MFA) for production enhancement in oil wells with gas lift. The tests were conducted in three wells with water cuts from 40 to 90%, depth (>5000 m), bottomhole temperature (150°C), and brine hardness and salinity up to 180,000 ppm and 310,000 ppm TDS, respectively. The MFA was coinjected with lift gas via the annulus and generated foam downhole as it mixed with reservoir fluids in the tubing. Tested MFA concentrations ranged from 160 to 750 ppm. The field tests demonstrated that the MFA was able to increase the oil production for a fixed gas lift injection volume. The MFA also enabled to reduce lift gas consumption, while maintaining or even increasing the original oil production.