New Approach for Using Surfactants to Enhance Oil Recovery from Naturally Fractured Oil-Wet Carbonate Reservoirs

Abstract

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.

Performance analysis of chemical flooding in fractured shale and tight reservoirs

“…The higher pressure gradient provides a higher force to drive the injection alkaline solution into matrix, resulting in higher oil recovery. Such result has been presented for surfactant injection in laboratory by Parra et al…”

“…The similar observation can be made for the alkaline flooding from this table. Parra et al proposed to increase microemulsion viscosity to increase the transverse pressure gradient from fracture to matrix for improved oil recovery in fractured reservoirs. This idea is tested in the shale models here.…”

“…Parra et al experimentally demonstrated that when the microemulsion viscosity was increased, the resulting higher pressure gradient improved oil recovery. In their experiments, the matrix permeability was 100–320 mD.…”

Experimental Study on Alternating Injection of Silica and Zirconia Nanoparticles with Low Salinity Water and Surfactant into Fractured Carbonate Reservoirs for Enhanced Oil Recovery

“…A lower flow rate of 0.007 mL/min is used after injecting brine at 0.03 mL/min because the injection of solutions at a lower flow rate in FCRs allows more resident time for the solutions to imbibe into the matrix and thus increases the oil recovery. 57 The injection of the LNS fluids alternatively begins when the residual oil saturation (S or ) is reached after the brine injection process. The cycle of the injection begins with LSWF at 0.03 and 0.007 mL/min flow rates until no further oil is recovered from the core.…”

Experimental study of microbial enhanced oil recovery in oil-wet fractured porous media

“…Nevertheless, such methods are generally more expensive than water injection, which makes them less attractive [7]. Therefore, improving the performance of water injection based methods in the oil-wet/ mixed-wet fractured reservoirs has been an attractive research topic [8][9][10][11][12][13][14][15][16]. Such improvement can be achieved by alkaline/surfactant injection (which leads to the reduction of the water/oil interfacial tension, capillary pressure and threshold height, creation of water/oil emulsions, and alteration of the matrix wettability) [17,18], polymer injection (which results in the enhancement of the mobility ratio) [18], and low salinity water injection (which causes wettability alteration) [19].…”